annual report 2010

Transcription

annual report 2010

COMMISSION FOR ELECTRICITY
AND GAS REGULATION
ANNUAL REPORT 2010
TABLE OF CONTENTS
1. Foreword . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
2. Main developments on the electricity and natural gas markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
2.1. Wholesale market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
2.1.1. Developments with regard to market concentration . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
2.1.2. Regional integration of the market. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
2.1.3. Development of electricity and gas exchange platforms . . . . . . . . . . . . . . . . . . . . . . . . . . 7
2.1.4. CREG activities aimed at promoting competition on the wholesale market. . . . . . . . . . . . . . . . . . 7
2.2. Retail Market. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
2.3. Public service obligations and consumer protection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
2.3.1. Putting in place the federal mediation service for energy. . . . . . . . . . . . . . . . . . . . . . . . . 8
2.3.2. CREG duties relating to disputes settlement. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
2.4. Infrastructure. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
2.4.1. Price trends in 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
2.4.2. Investments in the transmission system . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
2.4.3. Capacity allocation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
2.5. Security of supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
2.5.1. Powers of the CREG in terms of security of supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
2.5.2. Development of investment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
2.5.3. Development of supply/demand balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
2.5.4. Diversification of sources and routes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
2.6. Regulation/Unbundling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
2.6.1. Powers of the CREG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
2.6.2. Role of TSOs on the markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
2.6.3. Development of unbundling of TSOs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
2.7. Transposition of the third legislative package . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
2.8. General conclusions regarding the legal framework . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
3. Regulation and functioning of the electricity market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
3.1. Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.1.1. Management and allocation of interconnection capacities and congestion mechanisms . . . . . . . . . .
A. Regional and bilateral developments . . . . . . . . . . . . . . . . . . . . . . . . . . .
B. Market results on interconnections . . . . . . . . . . . . . . . . . . . . . . . . . . . .
C. Infringement proceedings against Belgium . . . . . . . . . . . . . . . . . . . . . . . . .
3.1.2. Regulation of transmission and distribution. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
A. Transmission and distribution tariffs . . . . . . . . . . . . . . . . . . . . . . . . . . .
B. Maximum prices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
C. Ancillary services and balancing. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
D. General terms and conditions of Access Responsible Party contracts . . . . . . . . . . . . . . . . .
3.1.3. Effective unbundling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.2. Competition aspects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.2.1. Description of the wholesale market. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
A. Electrical power demand. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
B. Electricity supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
C. Wholesale generation market . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
D. Energy exchange . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
E. Mergers and acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F. Price trends
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.2.2. Measures aimed at preventing abuse of a dominant position . . . . . . . . . . . . . . . . . . . . . . .
16
16
16
17
19
19
19
27
27
29
29
31
31
31
32
32
36
38
38
41
4. Regulation and functioning of the natural gas market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
4.1. Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.1.1. Management and allocation of the interconnection capacity and congestion mechanisms . . . . . . . . . .
4.1.2. Regulation of transmission and distribution. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
A. Transmission and distribution tariffs . . . . . . . . . . . . . . . . . . . . . . . . . . .
B. Maximum prices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
C. Code of conduct . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
D. Transmission model. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
E. Indicative transmission programme . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F. Standard connection contract . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.1.3. Effective unbundling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
48
48
49
49
52
53
53
55
56
56
4.2. Competition aspects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57
4.2.1. Description of the wholesale market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57
A. Natural gas supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57
B. Holders of a natural gas supply permit . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
C. Natural gas transmission permits . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60
D. Exchange platforms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60
E. Integration with intra-European regions and neighbouring member states. . . . . . . . . . . . . . . . 61
F. Integration between gas producers/importers and suppliers – long-term gas supply contracts . . . . . . . . . 62
G. Access to natural gas storage facilities . . . . . . . . . . . . . . . . . . . . . . . . . . 62
H. Developments in terms of market concentration . . . . . . . . . . . . . . . . . . . . . . . 63
I. Mergers and acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63
J. Price trends
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63
4.2.2. Measures aimed at preventing any abuse of a dominant position . . . . . . . . . . . . . . . . . . . . . 65
5. Security of supply. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .67
5.1. Electricity . . . . . . . . . . . . . . .
5.1.1. Demand . . . . . . . . . . . . .
5.1.2. Generation . . . . . . . . . . . .
5.1.3. Transmission grid infrastructures . .
5.2. Gas . . . . . . . . . . . . . . . . . .
5.2.1. Demand . . . . . . . . . . . . .
5.2.2. Supply . . . . . . . . . . . . . .
5.2.3. Measures in emergency situations .
5.2.4. Investment . . . . . . . . . . . .
5.2.5. Security of supply standards . . . .
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68
68
68
70
71
71
73
74
75
76
6. The CREG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .77
6.1. The assignments of the CREG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.2. The Bodies of the CREG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.2.1. The General Council. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.2.2. The Management Board . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.3. General policy plan and comparative report on the objectives and achievements of the CREG. . . . . . . . . . .
6.4. Cooperation with other bodies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.4.1. The CREG and the European Commission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.4.2. The CREG and ACER . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.4.3. The Madrid Forum. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.4.4. The Florence Forum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.4.5. The London Forum. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.4.6. The CREG within CEER and ERGEG. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.4.7. The CREG and the regional regulators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.4.8. Handling questions and complaints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.4.9. Participation of CREG members as speakers at seminars . . . . . . . . . . . . . . . . . . . . . . . . .
6.5. The CREG finances. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.5.1. The federal contribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
A. The federal contribution for gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
B. The federal contribution for electricity . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.5.2. The funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.5.3. The accounts for 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.5.4. The company auditor’s report on the financial year closed on 31 December 2010 . . . . . . . . . . . . . .
6.6. List of acts of the CREG during the year 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
78
78
78
82
84
84
84
84
85
86
86
87
88
89
90
91
91
91
91
92
94
97
98
LisT of tables
1Average import/export capacity and average nomination per year (MW) . . . . . . . . . . . . . . . . . . . . . .
2Annual revenues from capacities offered for auction (in millions of euros) . . . . . . . . . . . . . . . . . . . . .
3Congestion rents on coupled electricity exchanges per type of player (in millions of euros). . . . . . . . . . . . . .
4 Trend in the cost price for the transmission of electricity depending on the voltage, excluding surcharges and VAT . . .
5 Tariffs for the use of the distribution network in 2008, 2009 and 2010 (in €/kWh), excluding VAT. . . . . . . . . . . . .
6(Unweighted) average price of imbalances during the period 2007-2010 . . . . . . . . . . . . . . . . . . . . . .
7 Net supplies to customers connected to the federal transmission system for the years 2007 to 2010. . . . . . . . . .
8 Wholesale market shares in electricity generation capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9 Wholesale market shares in power generated . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10Energy exchanged and average price on the Intraday exchange. . . . . . . . . . . . . . . . . . . . . . . . . .
11 Breakdown of exchanges on the Day-ahead hub. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12 Breakdown of exchanges on the Intraday hub. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
13 Tariffs for the use of the distribution network in 2008, 2009 and 2010 (in €/kWh), excluding VAT. . . . . . . . . . . . .
14 Companies operating in the supply of natural gas on the Belgian market in 2010 . . . . . . . . . . . . . . . . . . .
15Market shares on the transmission system from 2007 to 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . .
16Power demand and peak capacity demand in Belgium during the period 2007-2010. . . . . . . . . . . . . . . . . .
17Breakdown of the installed capacity per type of power station connected to Elia’s grid,
per type of power station, as at 31 December 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18Breakdown of power generated per type of primary energy . . . . . . . . . . . . . . . . . . . . . . . . . . . .
19 Breakdown per sector of the Belgian demand for natural gas between 2001 and 2010 (in TWh) . . . . . . . . . . . .
20 Existing tools in the event of an emergency situation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
21 Members of the General Council as at 31 December 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
22 Directorates and staff of the CREG as at 31 December 2010. . . . . . . . . . . . . . . . . . . . . . . . . . . .
23 Overview of presentations given by the CREG in 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
24 Shortfalls recorded in the funds in 2010 (€) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
25 Income statement as at 31 December 2010 (€) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
26 Balance sheet as at 31 December 2010 (€) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18
18
19
20
23
28
32
33
33
37
37
37
51
59
63
68
68
68
71
75
81
83
90
91
95
96
List of figures
1 Availability and use of interconnection capacity from 2007 to 2010 . . . . . . . . . . . . . . . . . . . . . . . . .
2Average composition of distribution cost in Flanders in 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . .
3Average composition of distribution cost in Wallonia in 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . .
4Average composition of distribution cost in Brussels in 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . .
5 Structure of Eandis in 2009-2010 on the basis of the shares per DSO in Eandis . . . . . . . . . . . . . . . . . . . .
6Structure of Infrax in 2009-2010 on the basis of the shares per DSO in Infrax . . . . . . . . . . . . . . . . . . . .
7Structure of Ores in 2009-2010 on the basis of the shares per DSO in Ores . . . . . . . . . . . . . . . . . . . . .
8 (Unweighted) average price of imbalances and Belpex DAM price during the period 2007-2010 (in €/MWh) . . . . . .
9 Shareholding body of Elia as at 31 December 2010. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10 Average consumption on a monthly basis in the Elia control area for the 2007 to 2010 period (in MWh/h) . . . . . . . .
11 Average price on the Belpex, APX and EPEX FR exchanges between 2007 and 2010 (in €/MWh). . . . . . . . . . . .
12 Average monthly resilience of the Belpex market in 2007-2010 . . . . . . . . . . . . . . . . . . . . . . . . . . .
13Trend in average all-in price for electricity in 2009-2010 (in €/MW). . . . . . . . . . . . . . . . . . . . . . . . .
14Shares of the various components of the electricity price for Gaselwest-Electrabel household customers in 2010 . . . .
15 Trend in total electricity price – household customers (Dc) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
16 Trend in the price of energy per supplier – household customers (Dc) . . . . . . . . . . . . . . . . . . . . . . .
17 Trend in the energy price per supplier – business customers, average voltage (Ic1) . . . . . . . . . . . . . . . . .
18 Breakdown of the price of electricity in Brussels, Paris, Berlin, Amsterdam and London – June 2010 (€) . . . . . . . .
19Average composition of distribution cost in Flanders in 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . .
20Average composition of distribution cost in Wallonia in 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . .
21Average composition of distribution cost in Brussels in 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . .
22 Shareholding body of Fluxys as at 31 December 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
23Breakdown of supply per entry zone in 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
24Composition of aggregated supply portfolio of suppliers operating in Belgium in 2010 . . . . . . . . . . . . . . . .
25 Natural gas supplies by type and length of contract . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
26 IGH-Electrabel household customer – 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
27 Trend in total natural gas price – household customers (T2) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
28 Trend in energy price per supplier – household customers (T2) . . . . . . . . . . . . . . . . . . . . . . . . . .
29 Energy price trend per supplier – business customers (T4) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
30 Development of the natural gas consumption per sector during the period 1990-2010 (1990=100),
corrected for climate changes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
31 Breakdown per sector of the Belgian demand for H-gas and L-gas in 2009 and 2010 . . . . . . . . . . . . . . . . .
32 Forecasts demand for natural gas in Belgium until 2020 (GWh, normalised t°, H+L) . . . . . . . . . . . . . . . . . .
33 Market shares on the transmission grid in 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18
23
23
24
25
25
25
29
30
31
36
37
38
38
39
39
40
44
51
51
51
57
58
58
62
63
64
64
65
72
72
73
74
COMMISSION FOR ELECTRICITY
AND GAS REGULATION
ANNUAL REPORT 2010
1. Foreword
The year 2010 was marked by a number of significant developments both as regards the electricity and natural gas markets and
as regards the CREG.
At European level, last year saw the drafting by the European Commission of interpretative notes on the third legislative package so
as to guide member states when transposing this package into
their national legislation. The CREG took a proactive approach to
this matter, by providing the Belgian authorities, in complete transparency, with draft texts so as to apply the provisions of the third
package into Belgian law as well as possible. The main objectives
of the two directives and three regulations that make up this third
package are identical to those of the CREG: to improve the operation of the electricity and
natural gas markets by increasing transparency in network and supply activities, reinforcing
the rights of consumers, and vulnerable consumers in particular, supporting cooperation and
coordination at European level between network operators, regulators and member states, and
finally, by strengthening the independence and powers of the national regulators.
This transposition into Belgian law must be undertaken in accordance with European rules, in
the general interest and in particular in the interest of consumers. It is a matter of avoiding a
situation in which Belgium, as has happened in the past, becomes the subject of infringement
proceedings owing to the incorrect or insufficient transposition of European legislation in the
field of electricity and natural gas.
One of the main thrusts of the third legislative package also concerns the separation of energy
production and supply activities on the one hand from network activities on the other, also
known as unbundling. In this area, Belgium ranks among the leaders in Europe. Over the past
year GDF SUEZ, via Electrabel, sold its stake in the electricity and gas TSOs, Elia and Fluxys.
With regard to the distribution of electricity and gas, Electrabel has confirmed its intention to
reduce or even ultimately sell its stake in the mixed network operators.
In Belgium, the CREG fulfilled the assignments it has been entrusted with by federal and European law, on the one hand to advise the public authorities on matters concerning the organisation and operation of the electricity and natural gas markets and on the other hand to supervise
the market and monitor the implementation of applicable laws and regulations.
Last November, one of the highest courts in Belgium, the Constitutional Court, confirmed the
independence and autonomy of the CREG. It also stated that this autonomy is not compatible
with the submission of the federal regulator to hierarchical control or administrative supervision. However, the CREG has a duty to be transparent in the action it takes and must be able
to justify its decisions before Parliament, which exercises democratic control over each federal
body in the country, however independent it may be.
The efforts made by the CREG over a number of years were rewarded by the adoption at the
start of 2011 of its proposal for a Royal Decree on the code of conduct governing access to
CREG Annual report 2010
3
1. Foreword
the gas transmission system, the storage facilities and the LNG facilities. This code will make
a substantial contribution towards reinforcing competition and improving the operation of the
gas market in Belgium, as it provides for the abolition of the distinction between transit from
border to border and transmission for Belgian consumption, the implementation of new rules
on congestion and the secondary capacity market, as well as the improvement of transparency
on the gas market.
The CREG has also adopted a proactive attitude with regard to the government and federal
Parliament in the debate on the calculation of the profit generated by the operation of Belgian
nuclear power stations. On the basis of data provided by the electricity producers, the CREG
has delivered an estimate of this profit which is the most accurate established to date in Belgium by an authority.
Numerous reports, studies, opinions, proposals and decisions were drawn up by the CREG in
2010. The most important of these concern the opinion on the ten-year development plan for
Elia’s grid, the comparison of electricity prices in Brussels and in neighbouring capital cities,
the analysis of the quality of the electricity price indexation parameters, the examination of the
fixed price and variable price contracts offered by suppliers to household consumers, the analysis of the contracts concluded between electricity suppliers and major industrial consumers,
and the monitoring of the relationship between the costs and the selling prices of the gas
supplied to Belgian consumers.
Some of these acts may be compared to a spotlight trained on a particular aspect of the electricity and gas markets to reveal a dysfunction hitherto little known or unknown to most of the
market players and public authorities. This confirms that it is vitally important for Belgium to
have a strong and independent regulator on a liberalised electricity and gas market.
Reading this 2010 annual report, readers will note that the structure of the table of contents differs significantly from that used in previous years. The new structure, based on the report which
the CREG sends to the European Commission in July every year, already partly anticipates the
reporting obligations imposed by the third package on European regulatory authorities. Chapter
2 of this report reviews the main developments that occurred on the electricity and natural gas
markets. Readers will find a summary of the main elements that occurred in 2010 here, while
the following chapters cover each element in more detail.
François Possemiers
Chairman of the Management Board
April 2011
4
2. Main developments on the electricity
and natural gas markets
5
2. Main developments on the electricity and natural gas markets
This chapter provides an overview of the main developments that have occurred on the Belgian electricity and gas
markets. Some of the items are covered in greater detail
in Chapter 3 with regard to electricity and Chapter 4 with
regard to natural gas.
2.1. Wholesale market
2.1.1. D
evelopments with regard to market
concentration
Electricity
As regards supplies to major customers connected to
the federal transmission system1, the market share of
Electrabel was estimated at around 88.7%, up approximately 1.1 percent compared with 2009. The total volume of
energy taken up by end customers from the federal transmission system rose by almost 11% in 2010, increasing
from 12,332.8 GWh in 2009 to 13,714.0 GWh in 2010. Two
access points on the federal transmission system changed
supplier in 20102.
As regards the production market, the dominant position
of Electrabel clearly declined during the course of 2010, although it still remains very strong. The HHI3 of the production
market amounted to approximately 5,380 in 2010.
Natural gas
In 2010, a total of fourteen supply companies operated on
the Belgian market. Total natural gas consumption rose to
215.3 TWh, an increase of 10.9% compared with consumption in 2009 (194.2 TWh).
The merger between GDF and SUEZ and the fulfilment
of the conditions imposed by the European Commission
further to the approval of the merger in 2008 had a significant impact on the development of the market in 2010
and in particular on the market shares of Distrigas and GDF
SUEZ on the gas transmission market. With a 52.1% market share however, Distrigas still remained the dominant
player in 2010.
2.1.2. Regional integration of the market
Belgium again imported electricity on an annual basis in
2010, albeit only on a very small scale.
Until 8 November 2010, the markets were coupled via
Trilateral Market Coupling (TLC), involving Belgium, France
and The Netherlands. On 9 November 2010, the market coupling was extended to cover the Central West Europe region
(CWE), which means that the Belgian daily market is now
coupled, on the basis of implicit auctions, with France, Germany, Luxembourg and The Netherlands.
Via Interim Tight Volume Coupling (ITVC), also launched on
9 November 2010, the CWE region is also coupled with the
Scandinavian market by means of a mechanism based on
volumes (Volume Coupling).
Natural gas
Belgium occupies a strategic position as a hub in the natural gas systems of the North West region. This position is
reflected in the large number of interconnections with adjacent networks and the volumes of gas brought in for international transit and local supplies.
Whereas in previous years, congestion with regard to the
supply of entry capacity at the Eynatten and ‘s Gravenvoeren interconnection points remained an issue, this was overcome in 2010 thanks to the additional investments made. In
this respect, the introduction of the two-directional flow at
the Zelzate entry point and the reinforcement of the eastwest axis by means of the rTr2/VTN2 project rank among
the most striking achievements. In doing so, the main requirements were of course taken into account, but the market
is not yet fully integrated. Further investments will be required to be able to integrate the Belgian grid into the process
of European harmonisation.
Cooperation with neighbouring countries in investment
projects had already become a common practice through
coordinated investment projects (Open Seasons). In 2010,
all these projects gave rise to a final decision on a coordinated cross-border investment. Plans for implementation have
been put in place. Amongst other things, this success has
led to regional cooperation becoming an obligation in accordance with the new European regulations. In the future,
cooperation within the north-west regional initiative will therefore have to take on coordination and intensive follow-up
duties
Electricity
Having exported electrical power on an annual basis in
2009 for the first time since the liberalisation of the market,
Moreover, a new European survey has shown that - as with
the Belgian experience - the mechanisms for capacity allocation and the principles governing the management of
1 Grids with voltage in excess of 70 kV.
2 Source Elia (provisional data, January 2011).
3 The HHI index (Herfindahl-Hirschmann Index) is a commonly accepted measurement of the market concentration. It is calculated by squaring the market share of each company competing on a
market and adding up the figures obtained.
6
congestion at grid connection points are, on the whole, not
at all harmonised. Local and/or national markets continue to
be unduly organised along their own lines. This is why it was
recognised in 2010 that better structured cooperation was
needed to achieve market integration, at the very least with
regard to the form to be taken on by a unified, integrated
market.
This entire process requires a clear framework within which
progress can be made stage by stage towards a final model.
The wholesale markets such as the exchanges and hubs, on
which gas and electricity are traded among producers and
traders, are playing an increasingly important role in determining the prices paid by end customers. Cross-border issues
therefore also require cross-border surveillance. In this respect, the Agency for the Cooperation of Energy Regulators
(ACER) is to work closely with the national regulators, who
are also responsible for investigating any anomalies observed
and for imposing penalties, if and when required.
To define this target model, a discussion forum was set up
at the initiative of ERGEG at the end of 2010. The position
of all stakeholders will be heard and analysed by conducting workshops and external studies. Final conclusions are
expected in 2011.
2.1.4. CREG activities aimed at promoting
competition on the wholesale market
2.1.3. Development of electricity and gas exchange
platforms
In this context, as regards electricity, the Management
Board specifically focused on the regional integration of the
markets, the operation of the Belpex Day-Ahead Market, the
nuclear issue and the prices charged to end customers.
Electricity
In 2010, the coupling of the Day-Ahead markets between
Belgium (Belpex), The Netherlands (APX) and France (EPEX
FR) once again proved successful: in fact, the three markets
seldom operated in total isolation from one another. Belpex
and EPEX FR were coupled 87% of the time, Belpex and APX
73% of the time. Belgium was isolated from the other two
markets for just 1.2% of the time. The daily congestion rents
amounted to a total of € 33.3 million in 2010.
Natural gas
At national level, activity on the APX Gas ZEE gas exchange
remains very limited: 75 transactions were recorded there in
2010. This observation also means that the OTC trade (over
the counter) at the Zeebrugge hub remains the central element of the trade in Belgium.
In 2010, the CREG continued to undertake permanent monitoring of technical aspects and tariffs on the electricity and
natural gas markets.
As regards natural gas, the Management Board concentrated mainly on the regional integration of markets, promoting
liquidity on the wholesale market (by means of additional
investments and a plea for better support for the Zeebrugge
hub), the development of a competitive regional market for
low-calorific natural gas and the issue of costs and prices.
In addition, the CREG worked with the Competition Council.
Several members of staff from the CREG contributed to a
number of Competition Council dossiers as experts.
2.2. Retail Market
Price trends
Electricity
Even though in 2010 the total volume traded at this hub
reached a similar level to that of 2009, a significant increase
in liquidity was observed.
Moreover, new developments in the field of the regulations
governing hubs and exchanges are gathering speed at European level. In this context, the CREG has taken on a leading
role in the drafting of the ERGEG 2010 report on the monitoring of natural gas hubs4. It has also been closely following
the proposal from the European Commission for a new
European regulation on the integrity and transparency of the
energy market (REMIT)5.
Prices billed to end users continued to rise in 2010. This increase may be attributed to the way in which supply price
parameters developed. In addition, as regards the Flemish
Region, the unit price of the free kWh fell, with the result that
the discount for Flemish customers was smaller.
Moreover, the increase in the quotas to be supplied with
regard to the green certificates is resulting in a bigger contribution for renewable energy and cogeneration.
Finally, the federal electricity contribution has increased.
4 Monitoring Report 2010 on the regulatory oversight of natural gas hubs (http://www.energy-regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS_ERGEG_PAPERS/Gas/2010/E10GMM-11-03%20Gas%20Hub%20Monitoring%20Report%202010_final.pdf).
5 Proposal COM(2010)726 final for a Regulation of the European Parliament and the Council on energy market integrity and transparency, 8 December 2010.
7
Natural gas
Trend in electricity distribution tariffs
Prices billed to end users continued to rise in 2010. This
increase may be attributed to the increase in the price of energy linked to the trend in commodity prices. This increase
is partly offset by the reduction in transmission tariffs and
the fall in the federal contribution and the protected customer surcharge.
The 2009-2010 trend was considerably flatter than that
between 2008 and 2009 and may be attributed mainly to
the application of an indexation mechanism to the manageable costs and to a lesser extent to the trend in other
elements, such as depreciation and non-manageable costs
(public service obligations for instance). In 2010, imposed
tariffs were billed for two Walloon DSOs (Tecto and Wavre)
and for the «pure» (i.e. whose capital is held only by public
sector authorities) Flemish sector (Infrax West, Inter-Energa, Iveg and PBE). These are based on the most recent
corresponding total revenue elements approved, i.e. the
tariffs for the 2008 operating year.
2.3. P
ublic service obligations
and consumer protection
2.3.1. P
utting in place the federal mediation service
for energy
Trend in all-in electricity price
Although the procedure for appointing the French-speaking
federal energy mediator is still ongoing, the energy mediation service6 has been operational since 10 January 2010.
This service is qualified to deal with any disputes between
an end customer and an electricity or gas company and deal
with requests and complaints concerning the operation of
the electricity and gas market.
Prices charged to end users rose in August 2010 compared
with December 2009. This rise is due mainly to the trend
in supplier price parameters. A substantial increase in the
federal contribution and ‘renewable energy’ and ‘cogeneration’ contributions is also seen.
Trend in natural gas transmission tariffs
In the context of the cooperation between this service and
the energy regulators, the CREG has analysed a number of
complaints received by the mediator from end customers.
2.3.2. C
REG duties relating to disputes settlement
To date, it has not been possible to take up the new duties
assigned to the CREG in 2009 with regard to dispute settlement, which provide for the creation within the CREG of a
Mediation and Arbitration Service and a Litigation Chamber
(cf. 2009 Annual Report, p. 57). In fact, as at 31 December
2010 the implementing decrees required for this purpose
had not yet been promulgated.
2.4. Infrastructure
The new multi-annual tariffs for the transmission, transit and
storage of natural gas came into force in January 2010. These
tariffs, which result from an agreement between the CREG
and Fluxys, are valid until 31 December 2011. The agreement
also provides for stable tariffs until 2015. Moreover tariff predictability has been integrated in the longer term7.
The entry/exit tariffs (transmission and transit) have been
set in accordance with current European legislation, using a
methodology underlying the calculation of the tariffs which
is based on costs and applicable both to the transmission of
natural gas intended for the Belgian market and transmission from border to border. Equivalent principles have been
applied to determine storage tariffs.
These new transmission tariffs for Belgian consumers resulted in a 28% drop in tariffs compared with 2009.
2.4.1. Price trends in 2010
Trend in electricity transmission tariffs
As the tariffs charged for the use of the transmission system and ancillary services are multi-annual tariffs which
have been approved for the whole of the 2008-2011 regulatory period, they remained unchanged compared with 2008
and 2009.
The (indexed) tariffs for the use of the liquefied natural gas
terminal remain unchanged.
Trend in natural gas distribution tariffs
The 2009-2010 trend was considerably flatter than that
between 2008 and 2009 and may be attributed mainly to
the application of an indexation mechanism to the manageable costs and to a lesser extent to the trend in other elements, such as depreciation and non-manageable costs (for
instance, public service obligations). The provisional tariffs
6 Energy mediation service, rue Royale 47, 1000 Brussels; Tel.: 02/211.10.60; Fax: 02/211.10.69; E-mail [email protected]; website http://www.mediateurenergie.be/.
7 See 2009 Annual Report, p. 48.
8
applied by DSOs (Infrax West, Inter-Energa, Iveg and ALG)
were not made to change since the provisional tariffs for
2009-2012 are identical to the tariffs in force for the 2008
operating year.
Trend in all-in natural gas price
As was the case for electricity, which rose sharply in 2008
and fell again in 2009, the price of natural gas increased
again in 2010, without reaching the level seen in 2008 however. In 2009-2010, natural gas prices did not follow the trend
in oil prices.
2.4.2.Investments in the transmission system
Electricity
In 2010, Elia System Operator (hereinafter referred to as Elia)
and RTE, the operator of the French transmission system,
set up a second 225 kV three-phase circuit on an existing
electricity line stretching 15 kilometres between Moulaine
in France and Aubange in Belgium. A new type of electrical
conductor has been used on the new three-phase circuit and
on the existing circuit alike, making it possible to increase
the capacity of the circuits by over 20%. According to Elia,
thanks to this investment the exchange capacity between
France and Belgium can be increased by around 10 to 15%.
In addition, as part of the increase in the capacity of the
transmission system between the coastal region and the
interior of the country, a new 150 kV cable has been installed between the Blauwe Toren and Bruges sub-stations.
Natural gas
In terms of capacity allocation, in 2009, Fluxys launched
a subscription period procedure in consultation with and
under the supervision of the CREG so as to provide a solution to the problem of capacity congestion encountered
at certain entry points on the transmission system. This
procedure was included in the indicative transmission programme which constitutes a catalogue of the services offered by the TSO.
The subscription period procedure was amended as part
of the 2010-2011 indicative transmission programme on
the basis of feedback further to the 2009-2010 subscription
period8.
The feedback from the subscription period was used for the
launch of the consultation process on the basic principles
of an optimised transmission model, amongst other things.
On 23 November 2010, Fluxys submitted a new proposed
indicative transmission programme for the 2011-2012 period
in which the subscription period procedure has been abolished further to the assertion by Fluxys that no congestion
was expected on the transmission system during this period. The proposal was approved by the Management Board
on 8 December 20109.
2.5. Security of supply
2.5.1. Powers of the CREG in terms of security
of supply
Natural gas
Electricity
The investment programme of the TSO covers both the
forward-looking reinforcements of the gird aimed at supplying the Belgian natural gas market and the investments
to provide additional capacity for transmission from border
to border on the basis of long-term reservations. In 2010,
Fluxys, the TSO, allocated an investment budget of some
€ 400 million to reinforce the grid.
2.4.3. Capacity allocation
Electricity
The overall volume of commercial capacity available at the
borders during the course of 2010 did not undergo any significant changes compared with 2009, despite the increase in
unidentified flows due to the huge injection of wind energy
in northern Germany thanks to the use of phase-shifting
transformers, amongst other things.
The CREG continues to play a significant role in terms of
security of supply.
However, the CREG is not the only party to be involved
in this issue, given the Belgian institutional context on
the one hand and the distribution of powers of authority
between the regulator and the energy administration on
the other hand. While the regions have powers to settle
“the regional aspects of energy”, the federal authority remains qualified to address “matters whose technical and
economic indivisibility requires uniform implementation
at national level” in the listed cases, i.e. the national plan
for the equipment of the electricity sector, the nuclear
fuel cycle, major storage infrastructures, the transmission
and production of energy and the tariffs. In addition, the
federal authority can settle everything that comes under
the residual powers, which means that when a matter
8 Decisions (B)100114-CDC-938 and (B)100617-CDC-973.
9 Decision (B)101208-CDC-1029
9
cannot be linked to one of the powers attributed to the
regions, this matter comes under the federal scope of
authority. And so in principle new energy sources come
under the regional scope of authority. However, the federal authority remains qualified in the North Sea and for the
wind farms constructed in this zone in particular, owing
to the limitation of the territorial powers of the regions
to the territory of the region. The powers of the federal
authority are assumed either at the level of the federal administration, which is the Directorate General for Energy,
or at the level of the regulator, the CREG.
The construction of new power generation units is subject to the prior granting of an individual permit issued
by the Minister for Energy at the proposal of the CREG,
which is in charge of the examination of applications,
amongst other things. The domain concessions with a
view to the construction and operation of power generation units from water, currents or wind in marine areas
(wind farms) are granted by the Minister for Energy after
obtaining the opinion of the CREG.
As regards the outlook for long-term supplies, the CREG
is being consulted in the context of the drafting of a study
on the outlook for electricity supplies known as the ‘prospective study’. The CREG also has the power to advise on
the draft development plan for the transmission system
put forward by Elia.
The CREG also has the power to approve the methodology used to assess the primary, secondary and tertiary
reserve capacity, which contributes towards ensuring the
security, reliability and efficiency of the grid in the control
area. Similarly, it has to approve the market operating
rules intended to offset 15-minute imbalances.
Natural gas
The CREG plays a significant role in the field of security of
supply. The Act of 12 April 1965 on the transmission of gaseous and other substances by pipeline (referred to here as
the Gas Act) in fact stipulates that the CREG shall be consulted when drawing up the prospective study on the security
of natural gas supplies. However, the most recent achievement of the CREG in this area dates back to the publication
of the (F)090713-CREG-874 study of 13 July 2009 on natural gas supply needs, security of supply and infrastructure
development for the 2009-2020 time frame.
Moreover, European Regulation No 994/2010 which lays
down measures aimed at guaranteeing the security of natural gas supplies came into force on 2 December 201010.
This regulation lists the provisions aimed at maintaining the
security of gas supplies by guaranteeing the proper and
continuous operation of the internal natural gas market, by
enabling the implementation of exceptional measures when
the market is no longer able to provide the necessary gas
supplies and by precisely defining and attributing responsibilities among natural gas companies, the member states and
the European Union, both concerning preventive action and
the reaction to concrete disruptions of supply. This regulation also provides for transparent mechanisms, in a spirit of
solidarity, for the coordination of planning for, and response
to an emergency at member state, and regional level and
within the European Union.
Certain provisions in this regulation shall be implemented in
2011. These include the publication of public service obligations with regard to security of supply, the appointment of
the competent authority under the terms of this regulation,
the definition of protected customers and the preparation
of a risk analysis.
2.5.2. Development of investment
Electricity
n
Investments in generating units
With regard to prospective investments in onshore generating units known as at 31 December 2010, 946 MW are
under construction, 3,455 MW have been authorised11 and
2,502 MW are planned12. With regard to prospective investments in offshore generating units known as at 31 December 2010, 460 MW are under construction and 1,112 MW
have been authorised13.
n
Investments in the electricity transmission system
The main development in the transmission system for the
future is the Stevin project planned by Elia. This consists
of extending the 380 kV grid between Zomergem and
Zeebrugge.
10 Regulation (EU) N° 994/2010 of the European Parliament and of the Council of 20 October 2010 concerning measures to safeguard security of gas supply and repealing Council Directive 2004/67/
EC.
11 These 3,455 MW have been authorised but construction work has not yet begun. These are projects for which a generating permit has been granted (power plants of over 25 MW).
12 For which an application for authorisation is still being processed.
13 These 1,112 MW have been authorised but construction has not yet begun. These are projects for which a domain concession (offshore wind farm) has been granted.
10
This reinforcement of the grid is able to meet three needs:
• transporting the energy produced by wind farms at
sea to the interior of the country;
•
creating the conditions for a new interconnection
with the Belgian grid by means of a submarine link
with the United Kingdom;
• improving the security of the electricity supply in West
Flanders and enabling the continued economic development of the port of Zeebrugge.
n
The timing of the project depends largely on the length and
progress of the various authorisation procedures needed for
the construction of the project. These are scheduled to be
completed by the end of 2012. In this case, the actual work
could begin early in 2013 to be completed in 2014.
2.5.3. Development of supply/demand balance
Natural gas
n
Expansion of storage capacity
In the context of the gradual expansion of the underground
storage capacity in Loenhout, the useful storage volume
increased from 650 million cubic metres of natural gas in
2009 to 675 million cubic metres in 2010.
n
pen Season relating to the transmission capacity to the
O
Grand Duchy of Luxembourg
In the second quarter of 2009, Fluxys launched an Open
Season for the capacity between Belgium and the Grand
Duchy of Luxembourg. In this context, the capacities reserved as of 2015 are in line with expectations and will give rise
to limited investments.
Electricity
Belgium’s position on the international market depends
heavily on circumstances, and in particular on the economic situation. The sharp fall in Belgian electricity demand in
2009 compared to 2008 and the increase in installed capacity
created margins in the generating activities that enabled the
Belgian system to reposition itself on the international market. The recovery that began in 2010 caused these margins to
narrow. Belgium therefore moved from being a net importer
by 10,620 GWh in 2008 to being a net exporter by 1,835 GWh
in 2009 and back to being a net importer by 600 GWh in 2010
(source: Synergrid, provisional data for 2010).
Reinforcement of North Limburg
Natural gas
In 2010, a major extension was undertaken of the existing
H-gas pipeline from the Dilsen entry point to Lommel, in a
region supplied mainly by Dutch L-gas.
n
rTr2/VTN2
The laying of the rTr2/VTN2 pipeline parallel to the existing
bi-directional rTr1/VTN1 pipeline along a stretch covering
almost 170 km between Eynatten and Opwijk was the main
achievement in 2010.
n
Reinforcement of north/south axis
With regard to the north/south project, the new capacity
amounts to 10 billion m³ per year. The additional compression capacity needed for this north/south project is provided
at Winksele and Berneau.
n
pen Season relating the transmission capacity from
O
France to Belgium
The first non-binding phase of a market consultation process designed to gauge market interest in the transmission
capacity from France to Belgium was completed in 2010.
It will not be possible to begin the binding phase however
until the initiator, EDF, has decided to build a new LNG tanker terminal in Dunkirk. As at 31 December 2010, after a
number of postponements, a decision was still pending.
In 2010, total natural gas consumption amounted to
214.7 TWh, which represents a considerable increase
(10.6%) compared with consumption in 2009 (194.2 TWh).
This increase is due entirely to the strong recovery in industrial demand for natural gas (+19.7%), which has almost
returned to the 2008 level of consumption, and to a considerable increase in consumption on the distribution networks
(+15.5%).
Overall, the individual support portfolios of the various natural gas suppliers lead to differentiated supply depending
on the type of contract. The share of long-term contracts
concluded directly with the natural gas producers fell from
71.3% in 2009 to 60.3% in 2010, but still constitutes the
main component, with 2010 seeing a shift towards supplies
on the wholesale market.
The forecasts put forward by the CREG in 2009 with regard
to the supply/demand balance still apply as a reference framework for investments in the transmission system and for
security of supply.
The growth in demand in Belgium is mainly covered – at
least contractually – by the increasing imports of Russian
natural gas, while the share of Norwegian natural gas
contracts is stagnating and that of British natural gas continues to decline.
11
The role of LNG in covering demand is more difficult to
estimate as it depends on additional investments in the
LNG terminals. Nevertheless, the Zeebrugge LNG terminal
already plays a major role in supplying Belgium, at least in
the context of additional deliveries during peak consumption periods.
Although the 2009 gas crisis between Russia and Ukraine
did not disrupt the natural gas market in Belgium, it is recommended that Belgian energy policy follows this issue
closely and develops appropriate regulations to ensure the
security of supply.
2.5.4. Diversification of sources and routes
Gravenvoeren and the new physical entry point in Zelzate).
In fact, there are bi-directional connections with The Netherlands, Germany (and the United Kingdom), but not with
France. Physical imports from France are not possible at the
moment. To enable such physical imports, the Blaregnies/
Taisnières interconnection point will have to become a physical entry point for the Belgian market and a deodorisation
unit14 will have to be built on the French side.
The forecasts regarding the choice of entry points tally
with the grid reinforcements planned by 2020. Even then,
substantial entry capacity available in Eynatten and Zelzate
should enable increased supplies via these points.
2.6. Regulation/Unbundling
Electricity
In 2010, nuclear-generated electrical power accounted for
53% of the total electrical power generated in Belgium. The
share of electrical power generated using natural gas as the
primary fuel amounted to 30%.
In terms of capacity, nuclear energy and the CCGT together
with the gas turbines accounted for almost 35.7% and
27.2% respectively of the total installed capacity of the
power stations connected to Elia’s grid in 2010.
Natural gas
LNG supplies, mainly from Qatar, via the Zeebrugge terminal accounted for 6.2% of Belgian natural gas consumption in 2010, compared with 9.0% in 2009. With a share of
46.5%, Zeebrugge has once again confirmed its position as
the gateway to the Belgian market. For the L-gas market,
we observed fairly significant backhaul supplies from Blaregnies (4.9% in 2010 compared with 2.6% in 2009) on transit
flows initially intended for the French market.
The forecasts put out by the CREG in 2009 continue to apply. Natural gas suppliers operating on the Belgian market
have a differentiated supply portfolio in which the long-term
contracts concluded directly with natural gas producers
constitute by far the biggest element. Obtaining supplies
via the wholesale market is an option chosen mainly by the
new natural gas suppliers who have few, if any, direct purchase contracts in place with natural gas producers.
An analysis of the supply portfolios of importers (existing
or new) points to an upward trend in supplies via Germany (through Eynatten) and The Netherlands (through ‘s
2.6.1. Powers of the CREG
Over 2010, the chairman, three directors and sixteen
members of staff of the CREG were appointed inspectors
vested with the powers of authority of officers of the judicial police15. They are charged with seeking out and establishing infractions of certain provisions of the Gas and
Electricity Acts and of the relevant implementing decrees
across the territory of Belgium.
In addition, in a preliminary ruling (judgment No 130/2010
of 18 November 2010), the Constitutional Court stated that
the lack of hierarchical control or administrative supervision
over the CREG is not contrary to the Constitution in that
the CREG is an administrative authority with a considerable degree of autonomy and in addition is subject to both
jurisdictional and parliamentary control. The Court added
that the fact that the CREG fulfils its assignments with a
high level of autonomy results from the requirements of
European Union law, which has become gradually more
explicit in this area.
2.6.2. Role of TSOs on the markets
Electricity
On the electricity market, the operation of the power exchange is regulated by the Royal Decree of 20 October 2005
regarding the creation and organisation of a Belgian market
for the exchange of energy blocks. Article 6 of this decree
specifically outlines the behaviour and responsibilities of the
market operator and the TSO if the market is coupled to similar
markets. Pursuant to this article, the market operator may, in
14 In Belgium, natural gas is odorised (injection of an odorising substance to enable the detection of leaks, as natural gas is odourless) as soon as it is injected into the distribution networks. In the transmission system, natural gas is not really odorised because this creates problems for the chemicals industries that uses natural gas as a raw material. In France, however, natural gas is odorised in the
transmission system. Gas taken up by the chemicals sector is, if necessary, processed by an individual deodorisation plant.
15 Royal Decree of 25 June 2010 appointing the members of the Management Board and the members of staff of the Commission for Electricity and Gas Regulation, as officers of the judicial police (Belgian
Official Journalof 23 July 2010).
12
this case, at the request of the TSO, implement the methods
for the allocation of the available capacity to the market coupling for energy exchanges with foreign grids, provided that
this is done transparently and without discrimination.
In practice, Elia and Belpex use this Article 6. The Day-Ahead
capacity on the interconnections with The Netherlands and
France is implicitly auctioned on the Belpex Day-Ahead market. For annual and monthly capacities, the capacity on the
interconnections concerned is auctioned explicitly.
transposition of which was 3 March 2011. Other amendments to the Act were put forward at the same time so
as to improve the functioning and follow-up of the market,
resolve certain legislative difficulties and inconsistencies
and establish a logical structure for the Acts in question.
An initial study on the Act of 29 April 1999 relating to the
organisation of the electricity market (hereafter: the Electricity Act) was published in April 201016, followed by a
second version on 5 November 201017. On the same date,
a study on the Gas Act18 was also presented.
Natural gas
On the natural gas market, the operation of the hub and the
exchange is organised by Huberator and APX, which are not
regulated. The TSO, which is regulated, does not have a specific role to play on these markets. It is a member of the markets, in the same way as other parties, to obtain natural gas
supplies in line with its own needs.
2.6.3. D
evelopment of unbundling of TSOs
The electricity TSO
On 31 March 2010, the Elia Board of Directors approved the
agreement concluded between Elia, Publi-T and Electrabel/
GDF/SUEZ on the terms and procedures for the withdrawal
of Electrabel from the capital of Elia. Under the terms of
this agreement, Electrabel is selling 12.5% of the capital of
Elia to Publi-T, bringing Publi-T’s stake in the capital of Elia
to 45.37%.
The natural gas TSO
Further to an Act of 10 September 2009, in March 2010 GDF
SUEZ and Publigaz concluded an agreement on the transfer
of the entire stake of Electrabel in Fluxys (38.5%) to Publigaz. The transaction was effected on 5 May 2010. Further to
this transaction, Publigaz’s stake in Fluxys has increased to
89.97%, while the GDF SUEZ group has withdrawn entirely
from the capital of Fluxys.
2.7. Transposition of the third legislative
package
Over the course of 2010, the CREG carried out a number
of studies with a view to adapting the Gas and Electricity
Acts to the new European rules of the third energy package promulgated in July 2009, the final deadline for the
The amendments proposed are in line with the objectives of
the third energy package, and specifically relate to:
• increasing the independence and powers of the energy regulators;
• separating production and supply activities on the one
hand and grid activities on the other (unbundling);
• improving market transparency with a view to promoting equality of access to information, price transparency and consumer confidence in the market and
avoiding market manipulation;
• strengthening consumers’ rights;
• ensuring cooperation between European energy regulators through the newly created Agency;
• promoting cooperation between the TSOs.
2.8. General conclusions regarding
the legal framework
At a time when the procedure begun by the European
Commission with regard to Belgium’s infringements of the
second package is taking its course (see paragraph 3.1.1.C
below), the deadline for the transposition of the third European energy package is fast approaching. This will require
numerous significant modifications to the Belgian legal framework, including to the Gas and Electricity Acts. The modifications to be brought will enable the CREG to carry out its
general monitoring assignment in full.
Examples of the biggest modifications to be brought include the determination by the CREG of the conditions for
the connection and access to the grids and the rules on
capacity allocation and congestion management, the certification of TSOs, the problems inherent to closed distribution
networks, tariffs, grid development plans and the powers of
the CREG as a regulator.
16 Study (F)100416-CDC-962.
17 Study (F)101105-CDC-986.
18 Study (F)101105-CDC-984.
13
3. Regulation and operation
of the electricity market
15
3. Regulation and operation of the electricity market
3.1. Regulation
3.1.1. M
anagement and allocation
of interconnection capacities
and congestion mechanisms
in November 2009 the latter asked the TSOs to submit a
proposal based on an implicit (transmission capacity and
energy) and continuous allocation mechanism. The system
operators responded in February 2010 with an information
study. An adapted version of this study was produced in June
2010 in response to specific requests from the regulators.
A. Regional and bilateral developments
The growing importance of the regional integration of energy markets was pointed out in the third European legislative
package which stresses that the regional level is an essential first step towards a single European energy market.
The CREG is closely following the development of this issue
in the context of the electricity regional initiatives (ERI).
In 2010, the work on integrating the markets of the Central West Europe region (hereinafter CWE, which includes
Belgium) carried out under the leadership of the CREG related mainly to daily market coupling, setting up a regional
mechanism for Intraday exchanges, the auctioning rules for
cross-border transmission capacity and calculating interconnection capacities. Generally speaking, substantial delays
have built up with regard to these priority activities compared with the initial schedule.
One key objective is the creation of a flow-based D-1 market
coupling. To this end, the TSOs and regulators of the CWE
region have held a series of meetings to prepare for the
launch of CWE coupling, initially scheduled for May 2010.
The main aim of these meetings was to reach a better
understanding of the capacity calculation mechanism, the
congestion management methods and the methods used
to allocate the available daily capacity to the Access Responsible Party, as well as establishing a common position
on these matters and discussing the regulatory process.
Further to coordination with the volume coupling between
Germany and the Scandinavian countries and implementation problems in the final phase of the market coupling process, the CWE market coupling was finally launched on 9
November 2010. This coupling means that the Belgian daily
market is now coupled, on the basis of implicit auctions,
with France, Germany, Luxembourg and The Netherlands.
At the same time it also involves the coupling of the CWE
region with the Scandinavian countries through Interim Tight Volume Coupling (ITVC). At the moment, the CWE coupling is based on the Available Transmission Capacity (ACT)
and not on energy flows.
These developments in the CWE region gave rise to coordination between the energy regulators, the TSOs and the
electricity exchanges.
The CREG took a number of decisions in this context relating to the long-term, daily and Intraday markets.
On 7 October 2010, the Management Board approved the proposal put forward by Elia relating to the harmonised auctioning
rules for the CWE region, with the exception of Article 4.01
(b) (i), the application of which was authorised nonetheless so
as to avoid compromising the implementation of the improvements contained in the modified auctioning rules19.
Thanks to the harmonised auctioning rules, identical rules
apply throughout the CWE region for the allocation of interconnection capacity, whichever the required interconnection for the capacity. Moreover, market players wishing to
acquire annual and monthly interconnection capacity in the
CWE region can now contact a common auctioning body,
the CASC CWE.
Furthermore, the launch on 9 November 2010 of daily market coupling based on prices has also given rise to a number
of CREG decisions.
In February 2010, the Management Board issued an opinion
on the application for approval of the modifications proposed
by Belpex concerning the market rules of the Belpex market20. These modifications were introduced so as to enable
the implementation of market coupling of the Belgian,
Dutch and French hubs (Belpex, APX and EPEX Spot) to the
German hub (EPEX Spot). Further to this opinion, the Minister for Energy authorised the proposed modifications21.
The methodology used to calculate interconnection capacity
is based on existing methodologies to determine interconnection capacity. It is supplemented by coordinated monitoring of grid security by the TSOs of the CWE region, which
may result in a coordinated reduction in capacity. On 26
October 2010, the Management Board issued its decision
on the methodologies used to calculate daily capacities22.
The regulators of the CWE region also intend to set up a
regional Intraday mechanism. On the basis of consultation
with the market players in 2009 organised by the regulators,
19 Decision (B)101007-CDC-993.
20 Opinion (A)100211-CDC-946.
21 Ministerial Decree of 19 February 2010 approving modifications to the regulations on the energy blocks exchange market (Belgian Official Journalof 4 March 2010).
16
In October 2010, the Management Board also took a decision on the proposal put forward by Elia on the congestion
management methodologies and the methodologies used
to allocate the available daily capacity on the Belgium/
France and Belgium/Netherlands interconnections23. It
refused to approve the methodologiess proposed as they
failed to comply with Article 3.5 of the “Guidelines on the
management and allocation of available interconnection
transfer capacity of interconnections between national systems” annexed to Regulation (EC) 1228/2003 which aims
to achieve flow-based coupling. The Management Board
did however authorise the implementation of the proposed
coupling in the interests of the Belgian electricity market.
Finally, as regards the Intraday coupling mechanisms, the
CREG and the Dutch regulator NMa followed the development of a temporary bilateral Intraday mechanism between
Belgium and The Netherlands. This mechanism will be
based on the Elbas system which is already in place in the
Scandinavian countries. This will be a continuous and implicit system. To prepare for the adaptation of the market rules
to the specific features of this new Intraday market, the Management Board issued an opinion in September 2010 on
the modifications to the market rules24 proposed by Belpex.
Further to this opinion, the Minister for Energy authorised
the proposed modifications25.
the Belgian grid. For more details on this subject, see paragraph 5.1 of this report.
Thanks to the Intraday mechanism for interconnection
capacity introduced in May 2007 for the southern border,
469 GWh were imported from France and 392 GWh were
exported to France in 2010. Thanks to the Intraday mechanism for interconnection capacity introduced in May 2009
for the northern border, 78 GWh were imported from The
Netherlands and 100 GWh were exported to The Netherlands in 2010. Intraday connections were used slightly less
than 65% of the time in 2010, compared with 58% in 2009.
Figure 1 below shows the evolution of the import and export
capacity made available on the market on a Day-Ahead basis
(monthly average), as well as the related total net usage.
This figure shows that no extreme developments occurred
in 2010 in terms of the use (nomination) of interconnection
capacity: the monthly maximum average use was always
below 1,000 MW except in December (with average imports of 1,250 MW). This result contrasts with the results
obtained for 2008, marked by high imports during the period
from February to May, and for 2009, marked by high exports
during the period from July to September. Furthermore it
appears that the seasonal reduction in import capacity did
not get underway until May 2010, whereas in 2009 this occurred as early as March.
Moreover, in mid-2010 the TSOs of the CWE region, together with the British and Scandinavian TSOs, launched a
new North-West Europe (NWE) Intraday initiative. A clear
development plan will be prepared in 2011 to achieve implicit coupling on the Intraday markets in the CWE region, the
Scandinavian countries and the United Kingdom. The regulators in these countries are involved in these discussions.
B. Market results on interconnections
Having exported net electrical power on an annual basis in
2009 for the first time since the liberalisation of the market, Belgium again imported electricity on an annual basis
in 2010, albeit only on a very small scale. Net physical imports amounted to around 0.55 TWh in 2010, whereas net
exports amounted to 1.8 TWh in 2009. Gross physical imports in 2010 amounted to around 12.4 TWh, compared with
9.5 TWh in 2009, and gross physical exports were around
11.8 TWh, compared with 11.3 TWh in 2009.
A substantial proportion of the physical energy flows comes
from cross-border transiting of electricity passing through
24 Opinion (A)100930-CDC-990.
25 Ministerial Decree of 26 October 2010 approving modifications to the regulations on the energy blocks exchange market (Belgian Official Journalof 4 November 2010).
17
Figure 1: Availability and use of interconnection capacity from 2007 to 2010
MW
4.000
3.000
2.000
1.000
0
-1.000
-2.000
-3.000
-4.000
-5.000
Average export capacity
Average import capacity
2010/11
2010/09
2010/07
2010/05
2010/03
2010/01
2009/11
2009/09
2009/07
2009/05
2009/03
2009/01
2008/11
2008/09
2008/07
2008/05
2008/03
2008/01
2007/11
2007/09
2007/07
2007/05
2007/03
2007/01
-6.000
Average nomination
Source : CREG
The table below shows that average export and import capacity rose slightly in 2010 compared with previous years.
As regards import capacity, this increased in 2010 compared
with the previous years. The average nomination (use) was
positive in both years (indicating commercial exports), compared with negative nominations in 2007-2008 (indicating
commercial imports). In 2010, the Belgian control area was
a net exporter of energy.
Table 1: Average import/export capacity and average nomination
per year (MW)
Year
Average
export
capacity
Average
import
capacity
Average
nomination
2007
2,317
-3,908
-709
2008
2,242
-3,882
-1,196
2009
2,460
-3,877
319
2010
2,558
-4,023
17
Average
2,394
-3,923
-393
Source: Elia data, CREG calculations
The following table shows the trend in annual revenues from
(import and export) capacity acquired by market players in
the context of explicit auctions, valid for the following year
or the following month. This table shows that in comparison
with the past, the market players were able to obtain annual
and monthly capacity for a lesser amount in 2010 (€ 33.6
million).
18
So they anticipated the smaller price deviations in 2010 compared with previous years, indicating better convergence of
the markets in Belgium, The Netherland and France.
Table 2: Annual revenues from capacities offered for auction
(in millions of euros)
M€
Annual
auctions
Monthly
auctions
Total
2007
38.9
16.0
54.9
2008
27.1
11.6
38.7
2009
30.9
12.3
43.2
2010
25.5
8.1
33.6
When market players buy capacity, they estimate in advance
what they believe will be the price differences between
the Day-Ahead exchanges of the three countries (Belgium,
The Netherlands and France). These differences, which are
expressed on the short-term Belpex DAM market, indicate
that the interconnection capacity between two given markets is saturated. In principle, the resulting congestion rent
is allocated to the TSOs. However, if a market player buys
interconnection capacity at the explicit auction (annual and/
or monthly capacity) and fails to use it, this capacity is allocated to the implicit market coupling on the short-term
exchanges. The initial owner who has not used this capacity
subsequently receives the congestion rent if there is a price
difference in the direction of his capacity.
The trend in congestion rents, per type of player, over the
2007 to 2010 time period, as shown in the table below, reveals that in 2010 market players (‘resale’ in the table below)
received over half of the total congestion rents, i.e. a share
approximately equal to that of previous years.
In 2010, the total congestion rent also proved to be € 4 million lower than that of 2009, and as much as €10 million
lower than that of 2007 and € 11 million lower than that
of 2008, reflecting better convergence among exchange
prices. However, it should be noted that 2009 and to a lesser extent 2010 were crisis years in economic terms, which
could explain some of the price convergence.
Table 3: Congestion rents on coupled electricity exchanges per
type of player (in millions of euros)
M€
TSOs
Resale
Total
2007
23.7
19.5
43.2
2008
21.1
23.1
44.2
2009
16.6
20.7
37.3
2010
16.2
17.1
33.3
In practical terms, the main violations of the legislation noted
by the Commission were as follows: the first violation concerned a lack of information from the electricity TSO, which
hampers effective access to the energy suppliers’ network.
Secondly, the Commission considered the grid capacity allocation systems to be inadequate, preventing the best possible use of the electricity transmission systems. Finally, the
Commission criticised the lack of cross-border coordination
and cooperation between electricity TSOs and national authorities in the CWE region. The Commission believes that this
coordination and cooperation are necessary to allocate crossborder interconnection capacities more efficiently so as to
optimise the use of the electricity grid.
In August 2010 the Management Board sent the Minister
for Energy its report on the objections put forward by the
European Commission as set out in its reasoned opinion of
24 June 201026.
3.1.2. Regulation of transmission and distribution
A. Transmission and distribution tariffs
n The
As regards the calculation of commercial interconnection
capacities, a substantial proportion of the physical capacities is set aside as a security margin for loop flows through
Belgium, given their volume and unpredictability.
Finally, it should also be pointed out that as it has done
every year since 2008, in February 2010 the Management
Board conducted a study into Belpex, the Belgian shortterm market for electricity and the use of capacity on the
interconnections with France and The Netherlands for 2009
(see also paragraph 3.2.2.).
C. Infringement proceedings against Belgium
In June 2010, the European Commission sent Belgium,
along with twenty other European member states, requests
to implement and apply “in full various aspects of EU legislation intended to create a single gas and electricity market”. As regards the electricity market, the infringements for
Belgium, proceedings for which had been opened in June
2009, relate to the failure to comply with the legal obligation
resulting from Regulation (EC) 1228/2003 on conditions for
access to the network for cross-border exchanges in electricity (which came into force on 1 July 2004), as well as the
annexe (amended by a decision of 9 November 2006 which
came into force on 29 November 2006).
transmission system (Elia)
a) Methodology used to calculate the tariffs
The methodology used to calculate the multi-annual transmission tariffs of electricity (four-year regulatory period)
introduced by the Royal Decree on tariffs of 8 June 200727
has remained unchanged since 1 January 2008.
The system established by this Royal Decree is a normative secured revenue system in that it guarantees the TSO,
during a regulatory period of four years, sufficient total revenue to undertake its duties as defined by law and provide
a fair margin to remunerate the capital invested in the grid.
The revenue of each year in the regulatory period is divided
into manageable costs, that is costs over which the system operator exercises direct control, and non-manageable
costs, which are listed in the Royal Decree of 8 June 2007.
The total revenue is generated by the implementation of a
number of rules on the development of tariffs applied to the
revenue for the first year used as a benchmark to deduce
the revenue for the second, third and fourth year. Dividing
the total revenue for the four years by the total volumes to
be transmitted gives constant unit tariffs valid for the entire
regulatory period, except for exceptional circumstances or
changes to the services provided.
26 Study (F)100824-CDC-985.
27Royal Decree of 8 June 2007 on the rules on determining and monitoring the total revenue and fair profit margin, the general tariffs structure, the balance between costs and receipts and the basic
principles and procedures with regard to proposing and approving tariffs, reporting and cost control by the national electricity transmission system operator.
19
The most striking difference of this methodology compared
with the previous methodology based on a cost-plus regulation is the incentive for the TSO to stimulate its profitability
by means of the balance of manageable costs: every year,
the difference between the real manageable costs and the
budgeted manageable costs is in fact granted to the operator. However, the cost reduction stored up by the system
operator must ultimately (in the next regulatory period) also
give rise to tariff reductions for the benefit of grid users. This
incentive regulation system is also applied in other countries.
determine the fair profit margin provided that a TSO
does not demonstrate that another approach is more
suitable.
b) Tariff trends
The historic trend followed by transmission tariffs over time
since the start of regulation exercised by the CREG is illustrated below.
As the tariffs for use of the transmission system and for ancillary services are multi-annual tariffs that have been approved for
the entire 2008-2011 regulatory period. They remain unchanged in 2010 compared with 2009 and 2008.
The current tariffs system is also typified by:
• the implementation of a development rule applicable
to the manageable costs based on an indexation mechanism that includes both an ex-ante and an ex-post
calculation;
• the taking into account of an incentive to increase
investments. In fact, since 1 January 2008, when tangible fixed assets were decommissioned, the portion
of the capital gain relating to the assets concerned coming from the initial regulated assets can be imputed
to the total revenue to be covered by the tariffs, provided that the amounts corresponding to this capital
gain are booked as an investment reserve and consequently remain within the company and can be used
as a source of self-financing;
• the taking into account of congestion revenues for the
benefit of tariffs;
• the application of the CAPM (capital asset pricing
model), recommended by the Management Board to
c) 2009 balances
The Management Board also expressed an opinion on the
tariff balances relating to the 2009 operating year reported
by Elia28.
On the basis of the results of its monitoring programme
relating to the 2009 Annual Report, the Management Board
decided:
(i) not to approve the 2009 balances reported by Elia,
rejecting certain elements of the total revenue of
Elia (in particular the grossing up of the 2009 balance on the manageable costs) as well as the expenditure linked to the Black Start service provided
by the Drogenbos power plant;
Table 4: Trend in the cost price for the transmission of electricity depending on the voltage, excluding surcharges and VAT
Offtake in the grids
380/220/150kV
Offtake in transformation
to 70/36/30 kV
Offtake in the grids
70/36/30 kV
Offtake for transformation
to average voltage
7,000
6,500
6,000
5,500
Utilisation period (h/year)
Cost in
€/MWh
% compared
with the previous
period
Cost in
€/MWh
% compared
with the previous
period
Cost in
€/MWh
% compared
with the previous
period
Cost in
€/MWh
% compared
with the previous
period
2002 January-September (1)
6.4014
2002 October-December
and 2003 January-March
5.1503
-19.54%
6.7534
-25.65%
9.2888
-28.60%
11.532
-26,91%
2003 April-December
4.8239
-6.34%
6.3065
-6.62%
8.6259
-7.14%
10.9897
-4,70%
2004
4.4098
-8.58%
5.8862
-6.66%
8.2113
-4.81%
10.0685
-8,38%
2005
3.8417
-12.88%
5.1782
-12.03%
7.4714
-9.01%
8.7815
-12,78%
2006
3.4357
-10.57%
4.5834
-11.49%
7.0442
-5.72%
8.2754
-5,76%
2007
3.0232
-12.01%
4.1466
-9.53%
6.1883
-12.15%
7.3562
-11,11%
0verall fall 2007
compared with period (1)
9,0838
-52.77%
13.0100
-54.35%
15.7773
-52.43%
-53,37%
Start of multi-annual tariff 2008-2011 regulatory period
2008
3.5002
15.78%
4.9766
20.02%
7.7060
24.52%
9.1063
23,79%
2009
3.5002
0.00%
4.9766
0.00%
7.7060
0.00%
9.1063
0,00%
2010
3.5002
0.00%
4.9766
0.00%
7.7060
0.00%
9.1063
0,00%
0verall fall 2010
compared with period (1)
-45.32%
-45.22%
-40.77%
-42,28%
Source : CREG
20
28 Decisions (B)100512-CDC-658E/15 and (B)100625-CDC-658E/16.
(ii) to set the 2009 balance on the non-manageable
costs at the sum of € 7,921,062.24, which constitutes a regulatory claim in favour of Elia;
(iii)to set the 2009 balance on sales volumes at the
sum of € 14,789,000, which also constitutes a regulatory claim in favour of Elia.
d) Jurisprudence
In July 2010 Elia lodged an appeal with the Brussels Court
of Appeal for the annulment of the aforementioned decision by the Management Board on 25 June 2010. The appeal
ruling is expected in the first half of 2011 and should be
taken into consideration in the opinion on the allocation of
accumulated balances from the past four operating years
which the Management Board will pass on to the Minister
for Energy during the course of spring 2011.
e) Study on the comparison between the prices paid by
Elia for the purchase of energy to offset active losses
on its regional grids and the energy prices paid by
major industrial customers in 2009
In this study conducted in December 201029, the Management Board noted that for one of the thirteen batches of energy purchased by Elia, the purchase price was unreasonably
high. The Board is considering following up this finding in the
context of its decision on the operating balances for 2010.
n
The distribution networks
As with the transmission activity, a new tariffs regulation
methodology for distribution based on a guaranteed revenue for the DSO and supplemented by incentives aimed at
promoting cost control came into force on 1 January 2009.
This new system guarantees the DSO, for a regulatory period of four years, adequate total revenue to carry out its
legal duties and receive a fair profit margin to remunerate
the capital invested in the network.
The previous methodology, which was applied until 1 January 2009, adopted the cost-plus method, whereby the
costs incurred by the DSOs, monitoring by the CREG, were
increased by a profit margin offering a fair remuneration for
the capital invested in the distribution network. These tariffs
were approved by the CREG for a period of one year or, if
necessary, were imposed per quarter.
Three methodologies underlying the calculation of the tariffs are now possible during the aforementioned four-year
regulatory period:
• approval of the tariffs for the entire regulatory period if
the tariffs proposal accompanied by the network operator’s budget has been approved before the start of
the regulatory period;
• approval of the tariffs for the remainder of the regulatory period if the aforementioned tariffs proposal has
been approved during this period;
• the imposition of tariffs in all other cases.
On 30 September 2008, all the DSOs bar one submitted
a tariffs proposal accompanied by a budget for the 20092012 regulatory period within the legal deadline. As none of
the proposals submitted met the information requirements
stipulated by the Royal Decree of 2 September 200830, the
Management Board decided to reject these proposals and
impose provisional tariffs. The provisional tariffs imposed are
based on the latest elements of the corresponding approved total revenue, that is the tariffs for the 2008 operating
year. These provisional tariffs remain in force for the entire
duration of the regulatory period or until all the arguments
open to the DSO or the CREG have been exhausted or until
an agreement has been reached between on the points of
contention between the CREG and the DSO.
Over the course of 2009, most of the DSOs submitted
new tariffs proposals for the 2009-2012 regulatory period
on the basis of the new reporting model. The mixed DSOs
(in which both the public sector and the private sector have
capital holdings) whose operation was entrusted to the
companies Eandis (Flanders) and Ores (Wallonia) obtained
approved tariffs for the 2009-2012 regulatory period as of
1 July and 1 October 2009 respectively. The mixed DSO for
Brussels, Sibelga, and two «pure» Walloon DSOs, AIEG and
AIESH (whose capital is held only by public sector authorities) also obtained approved tariffs as of 1 October 2009. At
the end of 2010, the CREG concluded an agreement with
four pure DSOs whose operation has been entrusted to the
company Infrax (Infrax West, Iveg, Inter-Energa and PBE) on
pending points of contention so that their respective tariffs
have been approved as of 1 January 2011.
When assessing the tariffs proposals and the annual report
of the DSOs, the Management Board checked the separation between the network activities on the one hand and
any other activities undertaken by the network operator on
the other. It also checked the separation between regulated and non-regulated network activities. In this context,
the Management Board issued a number of guidelines31
29 Study (F)101208-CDC-991
30 Royal Decree of 2 September 2008 on the rules on determining and monitoring the total revenue and fair profit margin, the general tariffs structure, the balance between costs and receipts and
the basic principles and procedures with regard to proposing and approving tariffs, reporting and cost control by the national electricity transmission system operator.
31 Guidelines (R)100715-CDC-979.
21
defining a general framework for the assessment and treatment of regulated and non-regulated network activities.
The Management Board already pointed out on a number
of occasions in previous reports that the new regulatory
framework allows it few powers to assess the reasonable
and real nature of the costs as presented by the DSOs.
The Management Board is therefore of the opinion that the
legislation on the distribution tariffs needs to be reviewed
in accordance with the new European directive (Directive
2009/72/EC). The transposition of this directive will make it
possible to correct the legislation applicable to tariffs and
provide the regulator with the powers needed to guarantee
correct distribution tariffs32.
b) Tariffs trends
Table 5 provides an overview of tariff trends between 2008
and 2010. There are no changes for the DSOs upon whom
provisional tariffs have been imposed for the 2009-2012
period given that these are an extension of the tariffs applicable for the 2008 operating year. The 2009-2010 trend was
considerably flatter than that between 2008 and 2009 and
may be attributed mainly to the application of an indexation mechanism to the manageable costs and to a lesser
extent to the trend in other elements, such as depreciation
and non-manageable costs (public service obligations, for
instance).
In 2010, imposed tariffs were billed for two Walloon DSOs
(Tecto and Wavre) and for the «pure» Flemish sector (Infrax
West, Inter-Energa, Iveg and PBE). These are based on the
most recent corresponding total revenue elements approved, i.e. the tariffs for the 2008 operating year. These provisional tariffs remain in force for the entire duration of the
regulatory period or until all arguments open to the DSO or
the CREG have been exhausted or until an agreement has
been reached between on the points of contention between
the CREG and the DSO. During the last quarter of 2010, the
«pure» Flemish sector submitted new tariffs proposals for
the 2009-2012 regulatory period. As these new tariffs proposals include all the information and justifications required
by the Royal Decree of 2 September 2008, the Management Board approved the tariffs for 2011 and 2012.
Significant differences in tariffs are seen to exist between
the various DSOs. These may be explained on the one hand
by topographical and technical factors specific to the areas
supplied and on the other hand by the scope of the public
service obligations and whether or not the fee for occupation of the public domain is taken into account in the tariffs.
Other factors, such as the transfer of balances from the
previous years (bonus/malus) also contribute towards these
differences in tariffs.
Figures 2, 3 and 4 give the average composition of the distribution network cost in Flanders, Wallonia and Brussels.
32 Study (F)101105-CDC-986.
22
Table 5: Tariffs for the use of the distribution network in 2008, 2009 and 2010 (in €/kWh), excluding VAT
Tariffs:
Approved: A
Extended 2008: E
€/kWh
GRD
Household low voltage
3,500 kWh/year
Industrial average voltage
30,000 kWh/year
2008
2009
2010
Δ
2010/2009
0.0449
2008
2009
2010
0.0376
Δ 2010/2009
Industrial average voltage
1,250,000 kWh/year
2008
2009
2010
Δ
2010/2009
0.0142
AGEM
E
0.0449
0.0449
0.00%
0.0376
0.0376
0.00%
0.0142
0.0142
0.00%
AIEG
A
0.0360 0.0437 (3) 0.0452
3.26%
0.0458 0.0601 (3) 0.0678
12.69%
0.0154 0.0271 (3) 0.0279
3.14%
AIESH
A
0.0574 0.0681 (3) 0.0694
1.91%
DNB BA
E
pas applicable (1)
0.0601 0.0601 (3) 0.0616
2.52%
0.0237 0.0239 (3) 0.0245
2.57%
0.0809
0.0809
0.0809
0.00%
0.0300
0.0300
0.0300
0.00%
0.0650
0.0160
EV/GHA
E
0.0881
0.0881
0.00%
0.0650
0.0650
0.00%
0.0160
0.0160
0.00%
GASELWEST
A
0.0558 0.0641 (2) 0.0653
1.98%
0.0462 0.0446 (2) 0.0461
3.24%
0.0158 0.0157 (2)
0.0161
3.07%
GASELWEST WA
A
0.0506 0.0638 (2) 0.0602
-5.53%
0.0462 0.0446 (2) 0.0461
3.24%
0.0158 0.0157 (2)
0.0161
3.07%
IDEG
A
0.0576 0.0630 (3) 0.0632
0.22%
0.0441 0.0418 (3) 0.0421
0.81%
0.0164 0.0156 (3)
0.0156
0.13%
IEH
A
0.0481 0.0567 (3) 0.0567
-0.04%
0.0440 0.0468 (3) 0.0489
4.51%
0.0162 0.0171 (3)
0.0188
9.67%
IMEA
A
0.0461 0.0468 (2) 0.0477
1.87%
0.0419 0.0408 (2) 0.0417
2.15%
0.0148 0.0148 (2)
0.0150
1.43%
IMEWO
A
0.0881
0.0460 0.0524 (2) 0.0533
1.74%
0.0392 0.0381 (2) 0.0389
2.04%
0.0140 0.0140 (2)
0.0143
1.88%
0.0607
0.0607
0.00%
0.0320
0.0320
0.00%
0.0116
0.0116
0.00%
A
0.0697 0.0775 (3) 0.0771
-0.44%
0.0531 0.0536 (3) 0.0549
2.43%
0.0192 0.0197 (3) 0.0200
1.53%
INTERGEM
A
0.0470 0.0533 (2) 0.0544
2.04%
0.0382 0.0405 (2) 0.0418
3.11%
0.0135 0.0142 (2)
0.0146
2.61%
INTERLUX
A
0.0676 0.0736 (3) 0.0746
1.39%
0.0486 0.0466 (3) 0.0496
6.41%
0.0176 0.0166 (3)
0.0175
5.24%
INTERMOSANEA
0.0602 0.0693 (3) 0.0694
0.24%
0.0537 0.0550 (3) 0.0554
0.71%
0.0202 0.0209 (3) 0.0209
-0.14%
INTERMOSANE VLA
0.0602 0.0788 (3) 0.0789
0.09%
0.0537 0.0550 (3) 0.0554
0.71%
0.0202 0.0209 (3) 0.0209
-0.14%
0.0541
INTER-ENERGAE
0.0607
INTEREST
0.0320
0.0116
IVEG
E
0.0541
0.0541
0.00%
0.0420
0.0420
0.00%
0.0151
0.0151
0.00%
IVEKA
A
0.0427 0.0482 (2) 0.0490
1.59%
0.0373 0.0392 (2) 0.0400
2.07%
0.0126 0.0137 (2)
0.0140
1.91%
IVERLEK
A
0.0496 0.0543 (2) 0.0552
1.62%
0.0386 0.0397 (2) 0.0406
2.15%
0.0137 0.0143 (2)
0.0145
1.52%
PBE
E
0.0592
0.0592
0.0592
0.00%
0.0347
0.0347
0.0347
0.00%
0.0142
0.0142
0.0142
0.00%
PBE W
E
0.0500
0.0500
0.0500
0.00%
0.0333
0.0333
0.0333
0.00%
0.0133
0.0133
0.0133
0.00%
SEDILEC
A
0.0505 0.0555 (3) 0.0554
-0.24%
0.0399 0.0415 (3) 0.0423
1.83%
0.0147 0.0150 (3)
0.0152
1.13%
SIBELGA
A
0.0452 0.0505 (3) 0.0556
10.18%
0.0588 0.0483 (3) 0.0531
9.95%
0.0175 0.0147 (3)
0.0158
7.50%
SIBELGAS NOORD
A
0.0478 0.0523 (2) 0.0529
1.13%
0.0348 0.0462 (2) 0.0482
4.38%
0.0124 0.0165 (2)
0.0172
3.94%
SIMOGEL
A
0.0415
0.0471
0.56%
0.0427
0.0447
0.31%
0.0143
0.0150
0.0150
-0.09%
TECTEO
E
0.0451
0.0451
0.0581 (4) 28.65%
0.0531
0.0531 0.0647(4)
21.73%
0.0189
0.0189
0.0234 (4)
23.62%
WAVRE
E
0.0371
0.0371
0.0371
0.00%
0.0463
0.0463
0.0463
0.00%
0.0184
0.0184
0.0184
0.00%
WVEM
E
0.0628
0.0628
0.0628
0.00%
0.0436
0.0436
0.0436
0.00%
0.0160
0.0160
0.0160
0.00%
0.0528
0.0578
0.0588
1.87%
0.0460
0.0467
0.0483
3.00%
0.0163
0.0169
0.0175
2.54%
Average
0.0473
0.0420
0.0448
0.0151
(1) DNB BA does not serve any household customers
(2) Applicable as of 1 July 2009 (before this date the 2008 tariffs applied)
(3) Applicable as of 1 October 2009 (before this date the 2008 tariffs applied)
(4) Applicable as of 3 May 2010 at the earliest
Figure 2: Average composition of distribution
Source : CREG
Figure 3: Average composition of distribution cost
cost in Flanders in 2010
6.59%
in Wallonia in 2010
2.24% 1.33%
3.33% 1.21%
Subscribed and additional
capacity
8.66%
Subscribed and additional
capacity
12.61%
System management
2.76%
Measuring and metering activity
5.62%
Ancillary services
Public service obligations
Surcharges
System management
6.96%
Ancillary services
Surcharges
5.81%
Meter hire
Meter hire
6.14%
72.79%
Source: CREG
63.95%
Source: CREG
23
in Brussels in 2010
9.81%
Subscribed
and additional capacity
7.57%
System management
Ancillary services
18.35%
Surcharges
55.86%
4.20%
4.21%
Source: CREG
c) 2009 balances
In 2010, the Management Board processed the balances
of the DSOs relating to the 2009 operating year. For most
of them, a bonus was recorded on manageable costs and
a malus on non-manageable costs. The balance of manageable costs is included in the income statement of the
DSO while the Minister for Energy decides on the allocation of the accumulated balances of non-manageable
costs relating to the operating years 2008 to 2011 inclusive.
When processing the 2009 balances, particular attention
was paid to elements decommissioned by the DSOs and
the Management Board used a monitoring programme to
check whether the methodology proposed was observed
and whether the elements reported as having been decommissioned were actually decommissioned both in the field
and in administrative and accounting terms.
d) Jurisprudence
In 2010, the Court of Appeal in Brussels held a number of rulings further to the regulatory vacuum found with regard to its
jurisprudence, under which the Royal Decrees of 2 September 2008 had been declared unlawful. In response thereto,
the legislator had ratified the decrees in question (see 2009
Annual Report, pp. 28 and 51) but this did not alter the fact
that the decrees had been drawn up contrary to European requirements in this field (more specifically the ban on arbitrary
modification of the proposal put forward by the regulator).
Given this situation, the Management Board concluded in a
number of decisions that the CREG did not have a valid basis
to take decisions on tariffs.
In a number of rulings given on 29 June 2010, the Court of
Appeal in Brussels rejected this point of view with respect to
the rules on establishing the value of the regulated assets.
The CREG was ordered to reach a new decision, in application of the relevant provisions of the Royal Decree on tariffs.
24
These judgments were then extended in another series of
rulings on tariffs decisions taken by the CREG, in which the
Court had decided that the tariffs proposed by the DSOs
were valid ipso jure. The Court did however decide that it was
not impossible that the tariffs decisions had not been taken
in accordance with the directives on certain points, but not to
the extent that the Royal Decree had to be rendered unenforceable in its entirety. The Court specified that, moreover,
there was no reason why the CREG should not apply some
of the specific provisions concerned.
In order to put an end to the constant uncertainty, Infrax and
the CREG reached an agreement during the last quarter of
2010 concerning the tariffs to be applied during the last two
years of the 2009-2012 regulatory period. As a result, new
approved tariffs have been valid for all Infrax members since
1 January 2011. The legal proceedings with Sibelga, the Brussels DSO, have also been brought to a close and the tariffs
have been approved.
e) Operating companies of DSOs
The various operating companies fulfil all the assignments
and duties resulting from the obligations of the DSOs in
accordance with their articles of association. They have the
administrative bodies necessary for this purpose (Board of
Directors, Audit Committee, Human Resources Committee,
Corporate Governance Committee, etc.).
Eandis was incorporated on 30 March 2006. Seven Flemish
mixed DSOs (Gaselwest, Imea, Imewo, Intergem, Iveka,
Iverlek and Sibelgas) call upon Eandis to fulfil their operating
assignments in their regions. Figure 5 shows the Eandis
structure in 2009 and 2010 on the basis of the shares held
by each DSO in Eandis.
Infrax was incorporated on 7 July 2006 by the three «pure»
sleeping partners of Interelectra (now known as Inter-Energa), Iveg and Wvem (now known as Infrax West) to bring
together the operating activities in their region. PBE joined
Infrax in the course of 2010 and the electricity supplies of
the Havenbedrijf Antwerpen joined Iveg at the end of 2010.
Figure 6 shows the structure of Infrax in 2009 and 2010 on
the basis of the share held by each DSO in Infrax.
Ores was incorporated on 6 February 2009. It is the operator
responsible for the distribution networks for the eight mixed
DSOs in Wallonia (IDEH, IEH, IGH, Interest, Interlux, Intermosane, Sedilec and Simogel). Figure 7 shows the structure
of Ores in 2009 and 2010 on the basis of the shares of each
DSO in Ores.
BNO (Brussels Network Operations) performs duties at the instruction and on behalf of the mixed DSO for Brussels, Sibelga.
f) Studies carried out by the Management Board in 2010
Figure 5: Structure of Eandis in 2009-2010 on the basis
of the shares per DSO in Eandis
Studies on the purchase of energy to offset energy
losses by DSOs
2.51%
16.60%
19.43%
gaselwest
imea
imewo
intergem
13.76%
iveka
iverlek
sibelgas
14.34%
22.42%
Source: CREG
10.95%
Figure 6: Structure of Infrax in 2009-2010 on the basis
of the shares per DSO in Infrax
8.33%
59.38%
22.00%
19.79%
Having analysed the various purchase contracts, the CREG
noted that free competition for the allocation of the public
contract for the purchase of energy to offset the network
losses is limited in particular by the need for a regional supply permit and the power of the historic shareholder.
As of 2009, the first year of the 2009-2012 regulatory period, the costs of network losses are moreover considered
to be non-manageable, which takes away the incentive for
the DSOs to scrupulously follow the market so as to obtain
a more advantageous price.
12.50%
14.00%
In April 2010, the Management Board published a study on
the purchase of energy to offset energy losses by DSOs
between 2006 and 200833. This study analyses the energy
purchase contracts to offset energy losses on the electricity
distribution network. The purchase of this energy represents
one of the costs of the DSOs that are included in their tariffs
proposals and in their annual report, enabling the CREG to
monitor tariffs. The CREG notes purchase prices that sometimes differ greatly from one tariff proposal to another. The
competitive process should be more efficient for the supply
of this energy given the substantial volumes and technical
characteristics involved.
64.00%
inter-Energa
iveg
infrax West
PBE
Source: CREG
Figure 7: Structure of Ores in 2009-2010 on the basis
In December 2010, the Management Board carried out two
studies on the comparison between, on the one hand, the
prices paid by the mixed DSOs within Eandis and Ores to
buy energy to offset active losses on their regional networks
and, on the other hand, the energy prices paid by large industrial clients during the 2009 operating year.
of the shares per DSO in Ores
In its study on Eandis34, the Management Board noted
that the purchase prices paid by the DSOs were, generally speaking, in line with those charged by the main
suppliers operating in Belgium during the 2009 operating
year to their large industrial clients with comparable supply
characteristics.
5,61%
26,10%
15,53%
Ieh
Ideg
Igh
Interest
4,92%
Interlux
Intermosane
7,80%
13,29%
2,85%
23,90%
Sedilec
Simogel
Source : CREG
In its study on Ores35, the Management Board noted that
the prices obtained for each of the batches subscribed individually by each of the DSOs are substantially higher than
the commodity prices billed by the main suppliers operating in Belgium during the 2009 operating year to their large
industrial clients with comparable supply characteristics.
The excessive nature of the prices obtained is due partly
to the adjudication procedure followed by Netmanagement
and the need for potential suppliers to offer a fixed price by
which they are bound for several weeks.
33 Study (F)100401-CDC-958.
34 Study (F)101208-CDC-1001.
35 Study (F)101208-CDC-1005.
25
Studies on injection tariffs for high-quality renewable
energy production and cogeneration plants
In response to the request of the Minister for Energy, in
April 2010 the Management Board conducted a study on the
injection tariffs applied by certain DSOs, more specifically
on the desirability of a possible exemption from or abolition
of injection tariffs in favour of high-quality renewable energy production and cogeneration plants36. The Minister also
asked the CREG to examine the possible impact thereof on
the costs for various types of standard customers.
This study first of all stresses that any modifications made
to the legal framework which would lead to (full or partial)
exemption from or abolition of injection tariffs can only be
applied as of the next regulatory period, that is 2013-2016.
The study then goes on to demonstrate that, although a certain degree of clarification of the existing legislation is desirable, there are no legal obstacles to billing injection tariffs.
In addition, the Management Board worked out a number of
scenarios on the basis of a selection of standard customers
(Eurostat). The impact of a full and partial exemption from
injection tariffs on standard customers is calculated on the
basis of two scenarios. In view of the analyses carried out
and given that the injection tariffs can play a significant role
as a policy instrument in endeavouring to achieve an economic and social optimum in the context of the modernisation
of the distribution networks, the Management Board argues
in favour of maintaining injection tariffs in the legislation on
tariffs.
In July 2010, the Management Board conducted a followup study on the billing of injection tariffs for decentralised
producers where tariffs reflect the connection costs and
network use37. As regards the connection tariffs, the study
argues in favour of reflective costs. The obligation incumbent
on decentralised producers to pay the connection tariffs
they generate provides an incentive for localisation. The
possible application of percentage reductions to connection
tariffs may be considered. These reductions must, however,
be objective and in accordance with the law. Connection
tariffs that reflect the costs incurred imply adaptations to
the regulations in Flanders, for example.
As regards the use of the network itself (injection tariffs),
the study suggests billing these costs to the decentralised
producers who cause them. This means that the ‘system
management, ‘measuring and metering’ and ‘ancillary services – network losses’ tariff components would still be billed, but the ‘basic tariff for network services’ and ‘levies and
surcharges’ – provided the connection tariffs actually reflect
the costs – should be abolished. This would require an adaptation of the Royal Decree of 2 September 2008.
It should also be noted that in June 2010 Electrawind filed
an appeal for annulment against the application of injection
tariffs to the Constitutional Court.
Finally, in December 2010 the Flemish Parliament adopted a
decree with a view to avoiding injection tariffs for electricity
generated using high-quality renewable energy sources and
cogeneration38. This decree stipulates that the local distribution network or TSO carries out free of charge all the duties
needed for the injection of electricity generated using highquality renewable energy sources and cogeneration, with
the exception of connection to the local distribution or transmission system. The costs borne by system operator in this
case are considered to be costs resulting from the public
service obligations of the system operator as such.
Study on the development of the fixed term and/or capacity in the distribution network between 2003 and 2009
As regards electricity, the Management Board concluded in
this study conducted in December 201039 that the kW term
developed along virtually the same lines between 2003
and 2009, for both the tariff for the use of the network
and for the total annual costs of the distribution network,
and that consequently no notable change in the allocation
of costs occurred between kWh and kW. The downward
trend in costs attributed to kW compared with the total
budget is accentuated by the fact that the DSOs’ budgets
which are allocated to kWh have risen significantly over
the past few years (effects of jurisprudence, the extension
of public service obligations and multi-annual regulation),
which has led to a continued decline in the relative share
of the kW term.
As regards natural gas, as for electricity, the study concludes
that the kW term developed along virtually the same lines
between 2006 and 200940, for both the tariff for transfer
by the network and the total annual costs of the distribution network and that consequently no notable change in
the allocation of costs occurred between kWh and kW. The
36 Study (F)100401-CDC-959.
37 Study (F)100708-CDC-977.
38 Decree of 23 December 2010 amending the decree on Electricity of 17 July 2000 and the Decree of 8 May 2009 on energy, with a view to avoiding injection tariffs for electricity generated using
renewable energy sources and high-quality cogeneration (Belgian Official Journalof 20 January 2011).
39 Study (F)101202-CDC-1020.
40 Given that the CREG only approved tariffs for natural gas as of 2004 and that examination has shown that the kW term was not used before 2006, the results given are limited to the period
2006-2009.
26
relative share attributed to the kW term compared with the
total budget of a natural gas DSO is considerably higher
than for electricity. This phenomenon can be explained by
the fact that natural gas consumption depends far more on
the outdoor temperature than electricity consumption. By
maintaining the kW term, which is not linked to variations
in atmospheric conditions and the resultant consumption,
at a high level, the tariff fluctuations are lessened and this
makes it possible to offer more stable tariffs. As regards
the annual budget of the DSOs and the share allocated to
kW, this share follows a relatively steady trend.
In August 2010, the Management Board approved the proposal put forward by Elia concerning the method used to assess the primary reserve capacity and the result of applying
this method for 2011, but did not approve the proposal put
forward by Elia concerning the method used to assess the
secondary and tertiary reserve capacity and the result of
applying this method for 201142. The Board asked Elia to submit another proposal for the secondary and tertiary reserve.
Further to the additions and clarifications provided by Elia, the
Management Board finally approved the new Elia proposal in
December 201043.
g) Supplying information (tariffs, costs and connection
conditions)
However, to its decisions the Management Board did add
a number of considerations, amongst other things concerning the definition of a minimum tertiary reserve volume, the
need for Elia to have volumes in line with the decisions taken
by the CREG throughout the year, including in December, the
impact of the increase in the share of production by wind
farms in reserve volumes, the participation of industrial customers in the reserves and an extension of reserve monitoring.
All information is published on the websites of the network
operators. This obligation is imposed by the regional and
federal legislation.
The tariffs approved or imposed by the CREG can be
consulted on its website and on the sites of the network
operators. At the request of the CREG, most of them have
provided consumers with a calculation module that can be
used to make a detailed estimate of their transmission and
distribution tariffs.
B. Maximum prices
Readers are referred to paragraph 4.1.2.B of this report.
Prices and volumes for ancillary services offered by service providers
On 2 July 2010, the Management Board received the Elia report on the bids for ancillary services for 2011. The ancillary
services concerned include voltage adjustment and active
losses in Elia’s grids with a voltage of less than or equal to
70 kV. The other ancillary services will still be covered by
multi-annual contracts in 2011.
C. Ancillary services and balancing
Reserve capacity
Given that it was impossible to acquire the secondary reserves required for 2010 and 2011 at reasonable prices from
the producers in 2009, the Minister for Energy imposed price
and volume conditions for the supply of the secondary adjustment by various producers in 2010 and 201141.
In accordance with the federal network code for the management of the electricity transmission system and access to
this system (Royal Decree of 19 December 2002), 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 system in the
control area. It has an obligation to inform the CREG of its assessment methodology and the results obtained for approval.
On the basis of this report, in August 2010 the Management
Board approved a reasoned report44 which it transmitted to
to the Minister for Energy and to Elia, as required by law. In
this report, the Management Board concluded that the bids
for voltage adjustment are not blatantly unreasonable. The
report also states that it is not possible to reach a conclusion
on the prices for the entire volume which Elia estimates is
necessary to cover the losses of its regional network in 2011,
or to assert at the moment that all the prices resulting from
the auction session organised by Elia to cover the losses of
its regional network in 2011 are not blatantly unreasonable.
It may also be observed that the law allows for the possibility of assessing this price ex post, when the operating
balances for the current tariffs period are examined.
41 Ministerial Decree of 24 December 2009 imposing price and supply conditions for the supplying in 2010 and 2011 of secondary adjustment by various producers (Belgian Official Journalof 31
December 2009).
43 Decision (B)101223-CDC-1027.
44 Report (RA)100826-CDC-983.
27
This reasoned report from the CREG also contains a section
on the assessment of prices for the secondary reserve for
2011 imposed by ministerial decree45. This evaluation was
undertaken in application of Article 4, §2 of the Royal Decree of 11 October 2002 on public service obligations on
the electricity market. The results of this evaluation led to
the conclusion that there was no need to review the prices
imposed. A second evaluation was carried out at the end of
December 2010 which resulted in similar conclusions.
The HHI index relating to secondary and tertiary reserves
on generating units amounted to 3,750 in 2010 compared
with 5,800 in 2009. Activations relating to these resources
accounted for 97.9% of the total energy activated in 2010 to
offset imbalances in the control area, whereas in 2009 they
accounted for 99.0%.
The fall in the HHI index can be explained primarily by the
entry onto the market in 2010 of production reserves from
a third player, E.On.
Balancing
Price of energy to offset imbalances
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. In accordance with
the network code, Elia has to submit a proposal for market
operating rules intended to offset any 15-minute imbalances
to the CREG for approval.
In December 2010, the Management Board approved the
proposal from Elia for 201146. The proposed mechanism
came into force on 1 January 2011.
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 average price (unweighted) for positive imbalances
(injection>offtake) and the average price (unweighted) for
negative imbalances (injection<offtake) for the period from
2007 to 2010.
Table 6: (Unweighted) average price of imbalances during the
Activated volumes and concentration47
In 2010, activations to offset imbalances in the control area
rose by 26.6% compared with 2009 to reach 902 GWh.
The share of the secondary reserve in these activations
amounted to 76% in 2010, compared with 95.2% in 2009
and 98.5% in 2008. This fall is due in particular to a new
reserve activation procedure that has been gradually put in
place by Elia since October 2009.
In 2010, the activation of reserves located abroad by the
TSOs concerned accounted for 1.6% of Elia’s activations to
offset imbalances in the control area, compared with 0.7%
in 2009.
period 2007-2010
2007
2008
2009
2010
Injection > offtake
€/MWh
22.00
43.31
19.86
28.48
Injection < offtake
48.67
78.06
44.25
57.34
Source: Elia data
Figure 8 below can be used to compare these average
prices with the trend in average prices on the Belpex DayAhead market over the same period. It may be observed
that in 2010, compared with 2009, the average imbalance
tariffs rose more quickly than the average price of the Belpex DAM for both positive and negative imbalances.
45 Ministerial Decree of 24 December 2009 imposing price and supply conditions for the supplying in 2010 and 2011 of secondary adjustment by various producers (Belgian Official Journalof 31
December 2009).
46 Decision (B)101223-CDC-1028.
47 Source: Elia data.
28
Figure 8: (Unweighted) average price of imbalances and Belpex DAM price during the period 2007-2010 (in €/MWh)
90
80
70
60
50
40
30
20
10
0
2007200820092010
Injection > offtake
Injection < offtake
Belpex
D. G
eneral terms and conditions of Access Responsible
Party contracts
As regards the Access Responsible Party contracts proposed by Elia to network users, in 2010 the Management
Board issued five decisions approving a certain number of
modifications to the general terms and condition of these
contracts proposed by Elia, concerning respectively:
• the adaptation of definitions, the allocation of a balance perimeter, the harmonisation of deadlines in the
appointment procedure with a view to coupling markets in the CWE region48;
• the adaptation of the coefficient for offsetting active
losses on the transmission system during the year and
the adaptation of the balance perimeter should the
buy/sell contract relating to the production deviations
of the offshore wind farms be suspended49;
•
the harmonisation of deadlines in the nomination
procedure50;
• the introduction of continuous and implicit allocation
organised by the Belpex and APX Intraday electricity
exchanges on the Belgian-Dutch border51; and
• the clarification of the principles for the determination
of the balance perimeter of an Access Responsible
Party whose portfolio includes an access point to the
network from which a customer provides an interruptibility service in the presence of local generation operations at the same site52.
Sources: Elia and Belpex data
Moreover, the Management Board decided to withdraw decision (B)030320-CDC-130 of 20 March 2003 on the general
terms and conditions of the provisional agreement for the
non-exclusive use of Elia’s grid by eligible users connected
to the distribution networks established in the Walloon Region or the Brussels Region53. Appeals for annulment had
been filed with the Council of State against this decision of
20 March 2003 and in its report the Council of State Auditor concluded that a number of the arguments developed
by the applicants were legally valid, in particular the ratione
temporis power of the CREG to adopt the decisions under
attack, as the Act of 20 March 2003 amending the Act of
29 April 1999 had not yet entered into force at the time the
decision was taken. Taking note of this point of view, and
without any acknowledgement as to whether the other
arguments raised by the claimants are legally valid or not,
the CREG decided to withdraw the aforementioned decisions, in application of the general theory of the withdrawal
of administrative acts.
3.1.3. Effective unbundling
Unbundling of TSO
At federal level (voltage above 70 kV), there is only one TSO,
i.e. Elia System Operator, appointed on 13 September 2002
for a period of twenty years. Elia is also the TSO at local level
(grids from 30 to 70 kV).
51 Decision (B)101125-CDC-1019.
52 Decision (B)101202-CDC-1024.
53 Decision (B)101022-CDC-658E/17.
29
The TSO controls the physical assets of the transmission
system, as it controls Elia Assets, which owns the physical
assets.
Current Belgian legislation provides for the legal, functional
and accounting unbundling of the system operator but does
not stipulate any obligation for total ownership unbundling.
The main provisions with regard to unbundling for the system operator are laid down in the Electricity Act and the
amendments brought by the Act of 1 June 2005, as well as
the Royal Decree of 3 May 1999 on the management of the
national electricity transmission system. The provisions in
question relate to the legal structure, the composition of the
bodies of the company and its activities.
Belgian legislation forbids the TSO from taking out direct or
indirect stake in the shareholding body of the producers,
distributors, suppliers and intermediaries.
than those rendered necessary by its coordination activity
as TSO. Nor is it allowed to engage in the activities of a DSO
for voltages below 30kV. The system operator may undertake any activity on Belgian soil or abroad that is in line with
its object. These activities may not, however, have a negative effect on its independence or on the accomplishment
of the assignments it has been entrusted with.
In 2010, no modifications were made to the unbundling
rules that apply to the electricity grid TSO.
The structure of the Elia shareholding body as at 31 December 2010 is shown in Figure 9.
On 14 October 2010, Elia and TenneT transferred to APX-Endex their respective stake in the Belgian energy exchange
Belpex, i.e. 60% for Elia and 10% for TenneT. At the same
time Elia acquired a 20% holding in the capital of the APX
group, in which TenneT is the main shareholder.
In its capacity as a system operator, Elia is not permitted
to engage in any power generation or sales activities other
Figure 9: Shareholding body of Elia as at 31 December 2010
Free float*
Publi-T
Publipart
52.10%
45.37%
2.53%
Elia System Operator
Elia Asset
99.99%
Economic unit
CASC-CWE
HGRT
Coreso
Elia Re**
Elia Engineering**
APX-Endex
Eurogrid Int.
14.28%
24.50%
22.49%
100%
100%
20%
60%
* The Arco Group announced on 29 June 2010 that it holds 8.79% of the Elia shares.
** Elia System Operator owns one share in Elia Re and one share in Elia engineering.
30
Source : site Internet Elia
Developments in the first half of 2010
3.2. Competition aspects
On 31 March 2010, the Elia Board of Directors approved the
agreement concluded between Elia, Publi-T and Electrabel/
GDF/SUEZ on the terms and procedures for the withdrawal
of Electrabel from the capital of Elia. Under the terms of this
agreement, Electrabel is selling 12.5% of the Elia capital to
Publi-T. This will bring Publi-T’s stake in the capital of Elia to
45.37%.
3.2.1. Description of the wholesale market
Independence of system operator – Corporate
Governance
The CREG examined and commented on the activities report from the Elia corporate governance committee for 2009
(checking the application of Articles 9 and 9ter of the Electricity Act and assessing effectiveness with regard to the
objectives of independence and impartiality of the transmission system management).
In 2010, the Management Board issued a binding opinion on
the appointment of an independent administrator within Elia
to replace Ingrid Lieten54.
The report from the Compliance Office describing the measures taken by Elia during 2009 to ensure that all discriminatory practices are ruled out and ensuring appropriate monitoring
of the programme of commitments provided for by Article 8,
§2 of the Electricity Act was examined by the CREG, which did
not have any observations to make on this matter.
A. Electrical power demand
According to the statistics passed on to the CREG55, the
electrical power demanded by Elia’s grid excluding pumped storage, in other words the net consumption plus grid
losses, was estimated at 84,733 GWh in 2010, compared
with 80,194 GWh in 2009, which would mean an increase
of approximately 5.66%. The demanded peak capacity was
estimated at 13,585 MW56, against 13,320 MW in 2009.
Figure 10 provides an overview for the period 2007 to 2010
of the average consumption on a monthly basis in the Elia
control area. After a sharp fall in electricity consumption in
October 2008 as a result of the economic crisis, which continued in 2009, consumption rose again in early 2010. Although
these figures are not adjusted to factor inthe temperature in
the month in question, they do reflect the trend well.
These consumption data do not entirely take into account
local generation. It is presumed that this local generation is
increasing year on year. For 2009, Synergrid estimates local
generation at 7.9 TWh, or almost 10% of total consumption. The CREG does not have any more recent data at the
moment.
Figure 10: Average consumption on a monthly basis in the Elia control area for the 2007 to 2010 period (in MWh/h)
11.500
10.998
11.000
10.976
10.871
10.500
10.413
10.240
10.000
9.761
9.500
9.628
9.302
9.000
9.444
9.344
8.819
8.500
8.774
8.000
1
2
2007
2008
3
4
2009
2010
5
6
7
8
9
10 11 12
54 Opinion (A)100318-CDC-955.
55 These statistics have been supplied by Elia and do not cover the total electrical power demand in Belgium as they do not take into account the small local generating units for which Elia does not
take any measurements (<25 MW), or the generating units that are not connected to Elia’s grid for which Elia does not have any measurements.
56 Source: Elia, provisional data, January 2011.
31
B. Electricity supply
Table 7 shows the market shares of Electrabel and the other
suppliers as regards net electricity supplies57 to major industrial customers connected to the federal transmission system (grids with voltage levels higher than 70 kv). According
to an initial estimate, of Electrabel’s market share amounted
to approximately 88.7% in 2010, up approximately 1.1
percent compared with 2009. The total volume of energy offtake by end customers from the transmission system rose in
2010, increasing from 12,332 GWh in 2009 to 13,714 GWh in
2010. Two access points on the federal transmission system
switched to a different supplier in 2010.
the transmission system: Anode, Duferco Energia, Electrabel,
Endesa Energia, E.On Belgium, E.On Energy Sales, Essent
Energy Trading, Gaselys, Nuon Belgium, Pfalzwerke, RWE
Energy Belgium, RWE Key Account and SPE.
C. Wholesale generation market
This paragraph deals with generating units connected to
Elia’s grid (voltage level equal to or above 30 kV).
Table 7: Net supplies to customers connected to the federal transmission system for the years 2007 to 2010
Consumption
sites
1 January 2010
Consumption
sites
31 Dec. 2010
Electrabel S.A.
71
71
Other suppliers
12
14
79*
81*
Suppliers
Total
Power offtake in
2007 (GWh)
Power offtake in
2008 (GWh)
Power offtake in
2009 (GWh)
Power offtake in
2010 (GWh)
12,468.6
11,470.3
10,806.5
12,162.7
(87.7%)
1,742.7
(84.0%)
2,183.3
(87.6%)
1,526.3
(88.7%)
1,551.2
(12.3%)
(16.0%)
(12.4%)
(11.3%)
14,211.3
13,653.6
12,332.8
13,714.0
* Four consumption sites were supplied by two suppliers simultaneously.
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 2010, the Management Board received
four permit applications: two applications to renew a
supply permit whose period of validity had expired (Essent
Belgium and E.ON Energy Trading whose company name
was previously E.ON Sales & Trading GmbH) and two new
applications from Pfalzwerke and Enovos Luxembourg, who
are not yet operating on the federal transmission system.
The Management Board issued a total of three proposals
over the course of 201058.
In 2010, the Minister issued permits for Essent Energy
Trading, RWE Supply & Trading and Pfalzewerke59 and, at
the request of the company, terminated the supply permit
of RWE Key Account60. As at 31 December 2010, no decision
had yet been reached on the (positive) proposals for Essent
Belgium and Enovos Luxembourg.
As at 31 December 2010, thirteen suppliers held a federal
permit to supply electricity to end customers connected to
Source: ELIA (provisional data, January 2011)
Whosale generation market shares
Table 8 gives an estimate, in both absolute values (in GW)
and in relative shares of the Belgian total (in %) of the market shares in the electricity generation capacity at the end
of each year.
The table shows that, although Electrabel saw its market
share fall in 2009 and 2010, it still holds a very high market
share (72%) of the total generation capacity. The second
largest player is SPE/EDF, with a market share of 15% of
the generation capacity. The third player in Belgium is the
German company E.On, which has acquired 9% of the generation capacity through a swap with Electrabel in early
November 2009.
The HHI, a widely used concentration index, remained very
high in 2010 at 5,500. By way of comparison, a market is
considered highly concentrated if the HHI is equal to or
above 2,000.
57 These figures do not take into account the energy supplied directly by local generation.
58 Proposals (E)101202-CDC-1009 (Essent Belgium), (E)101014-CDC-1000 (Pfalzwerke) and (E)101125-CDC-1022 (Enovos Luxembourg).
59 Ministerial Decrees of 1 February as regards RWE Supply & Trading (Belgian Official Journalof 10 February 2010), 22 February 2010 as regards Essent Energy Trading (Belgian Official Journalof 3
March 2010) and 22 December 2010 as regards Pfalzwerke (Belgian Official Journalof 29 December 2010).
60 Ministerial Decree of 20 January 2010 (Belgian Official Journalof 28 January 2010).
32
Table 8: Wholesale market shares in electricity generation capacity
GW
Electrabel
2007
2008
2009
2010
2007
2008
2009
2010
13.4
13.7
12.3
11.7
86%
85%
75%
72%
9%
10%
11%
3%
3%
3%
SPE
1.4
1.5
1.8
EdF
0.5
0.5
0.5
E.On
0.0
0.0
1.5
1.5
0%
0%
9%
9%
RWE/Essent
0.3
0.3
0.3
0.3
2%
2%
2%
2%
Players < 2%
0.0
0.0
0.1
0.4
0%
0%
1%
2%
15.6
16.1
16.5
16.2
100%
100%
100%
100%
HHI
7,460
7,350
5,770
5,500
Total
2.4*
* The shares of SPE and EDF have been combined for 2010 as SPE has been taken over by EDF.
Table 9 gives the same estimate but in terms of the amount
of power actually generated. This shows that, in terms of
generated power, the Electrabel market share is equal to its
market share in generation capacity. This means that its average utilisation rate of generating resources is more or less
equal to that of the other producers. This is also true of the
second player, SPE/EDF. The share of the third player, E.On,
amounts to 11% of the power generated, which means that
its utilisation rate of generating resources is higher than
the average. The opposite is true for the small players who,
even together, hold a market share of less than 1%.
Although it remains very strong, the dominant position of
Electrabel clearly declined in 2010, both in generation capacity and in generated power. The HHI61 of the generation
market stood at around 5,380 in 2010. By way of comparison, a market is considered highly concentrated if the HHI
is equal to or above 2,000.
15%*
Permits for new generating plants
The construction of new power generation plants is subject to the prior granting of an individual permit issued by
the Minister for Energy at the proposal of the CREG. In
this context, in 2010 the Management Board made three
proposals with regard to the granting of a generating permit62. These related to applications from Dils Energie for
the construction of two CCGT plants in Dilsen (Dilsen-Stokkem), Stora Enso Langerbrugge for the construction of a
cogeneration plant in Langerbrugge (Ghent) and Electricité
du Bois du Prince for the extension of a wind farm in Mettet/
Fosses-la-Ville. As at 31 December 2010, seven applications
for individual generating permits were being processed by
the CREG.
Table 9: Wholesale market shares in power generated
2007
2008
2009
2010
2007
2008
2009
2010
Electrabel
TWh
72.6
67.1
66.9
60.0
87%
85%
81%
72%
SPE
5.6
5.6
7.9
7%
7%
10%
EdF
3.5
3.6
4.1
4%
5%
5%
E.On
0.0
0.0
1.4
8.8
0%
0%
2%
11%
RWE/Essent
2.1
2.2
2.2
2.4
2%
3%
3%
3%
12.1*
14%*
Players < 2 %
0.0
0.0
0.1
0.4
0%
0%
0%
0%
Total
83.8
78.5
82.6
83.7
100%
100%
100%
100%
HHI
7.570
7.380
6.680
5.380
* The shares of SPE and EDF have been combined for 2010 as SPE has been taken over by EDF.
62 Proposals (E)100503-CDC-970, (E)101125-CDC-1021 and (E)101202-CDC-1023.
33
In 2010, the Minister granted a permit for the construction
of a coal-fired power plant in Antwerp by E.On Power Plants
Belgium, for which the Management Board had issued a
proposal63 in 2009, as well as for the Dils Energie project,
bringing the additional authorised generation capacity to
around 2,000 MW64.
In addition to the applications for new generating permits,
in 2010 the Management Board examined a notification of
a change in control from SPE, which the CREG received in
December 2009. The Management Board’s proposal65 was
passed on to the Minister for Energy, who decided to accept it.
The legal powers of the CREG in this area are detailed in
paragraph 5.1.2. of this report.
Offshore wind power generation
a.2. Applications submitted to the CREG
Four of the five proposals relating to the granting or the
modification and extension of domain concessions which
the Management Board sent to the Minister for Energy in
2009 gave rise to two ministerial decrees in 2009 granting
such concessions respectively to Rentel and Norther68 and
to three ministerial decrees in 2010 granting concessions to
C-Power69, Seastar70 and Elepasco71 respectively.
The proposal from the Management Board concerning zone
G gave rise to a negative decision from the Minister. The
procedure relating to the granting of the above domain
concession for zone G was subsequently suspended.
b) Green certificates and guarantees of origin
In 2009, the Management Board approved a proposal aimed
at introducing a federal system of guarantees of origin for
electricity generated by offshore wind farms72.
a) Domain concessions for offshore wind energy
a.1. The regulatory framework
In November 2010, at the request of the Minister for Energy,
the Management Board again66 published an opinion67 on
the draft amendment of the Royal Decree of 20 December 2000 which would bring into effect an adaptation of the
zone intended for the location of offshore installations. In
this opinion, amongst other things the Management Board
arrived at the conclusion that the surface area of the zone G
was being reduced by around 27 km² and that consequently
it would be advisable to offset the surface area removed
from this zone elsewhere. As at 31 December 2010, no
Royal Decree amending the Royal Decree of 20 December
2000 had yet been published.
While awaiting this amendment, the procedure relating to
the granting of the domain concession situated above for
the Blighbank zone (zone G) has been suspended (Belgian
Official Journal of 26 February 2010).
In May 2010, the Management Board approved a proposal73
that extends and clarifies the method used to measure and
calculate net green electricity generation.
At the end of 2010, these proposals had not yet given rise to
the adoption of a Royal Decree.
In addition, in July 2010 the Management Board approved
the proposed modification of the contract to be concluded
between Elia and Belwind relating to the purchase of green
certificates for electricity generated using offshore wind
energy74. The proposed modification concerned the method
used to measure and calculate the net green electricity
generated.
Finally, in 2010 the Management Board took three decisions
on the granting of green certificates for the Belwind offshore windturbines located on the Blighbank75. These are
decisions in principle setting the date as of which the windturbines fulfil the conditions for obtaining green certificates.
63 Proposal (E)090827-CDC-891.
64 Ministerial Decrees of 23 June 2010 (Belgian Official Journalof 29 June 2010) as regards E.On Power Plants Belgium and 27 July 2010 as regards Dils Energie (Belgian Official Journalof 6 August
2010).
65 Proposal (E)100204-CDC-942.
66 2009 Annual Report paragraph 2.4.5.1.1., p. 18.
67 Opinion (A) 101104-CDC-1013.
68 2009 Annual Report, paragraph 2.4.5.1.2., p. 18.
69 Ministerial Decree of 3 February 2010 (Belgian Official Journalof 16 February 2010).
70 Ministerial Decree of 24 March 2010 (Belgian Official Journalof 6 April 2010).
71 Ministerial Decree of 24 March 2010 (Belgian Official Journalof 6 April 2010).
72 2009 Annual Report, paragraph 2.4.5.2., p. 18.
73 Proposal (C)100527-CDC-971.
75 Decisions (B)101118-CDC-1012, (B)101125-CDC-1015 and (B)101216-CDC-1030.
34
At the end of 2010, the installed capacity in offshore wind
turbines amounted to a total of 195.9 MW for the six CPower wind turbines that were constructed in 2009 and
165 MW for the 55 wind turbines constructed by Belwind in
2010. In 2010, 189,237 green certificates were granted for
electricity generated by offshore wind turbines during the
year 2010.
c) Support measures in favour of green electricity
At the request of the General Council, the Management
Board conducted a study on the total costs of the three
support measures granted to offshore wind farms76. These
measures, laid down in Article 7 of the Electricity Act, are:
• t he sale of green certificates at a guaranteed minimum
price;
• t he contribution of the TSO to the submarine cable and
the connection installations; and
• t he production variance mechanism.
The Management Board produced an objective and cautious estimate of the annual cost in €/MWh for the normal
operation of a single, complete farm of 300 MW. Its initial estimate of the surcharge amounted to € 1,295/MWh,
taken up on 84 TWh. This was to cover an annual cost of
€ 108,250,000, with the purchase of green certificates alone
accounting for 92%.
The Management Board also conducted a study which
sheds light on the various support mechanisms for green
electricity in Belgium77. The cost of support mechanisms is
billed to the end customer via distribution tariffs (in Flanders
only) and by a ‘renewable energy’ and ‘cogeneration’ contribution charged by the suppliers (in Flanders, Brussels and
Wallonia).
Over the past few years, the public service obligations in
the Flemish distribution tariffs have risen sharply, amongst
other things owing to the obligations to purchase green certificates. The CREG analysed the Flemish minimum prices
(set by calculating the non-profitable proportion78). A very
high return on equity requirement is included in the calculation of the non-profitable portion, even though investments
in renewable energy may be considered virtually risk-free
owing to the guaranteed minimum price for the entire
management period. The scenarios developed by the CREG
result in a far lower non-profitable portion for photovoltaic
cells and onshore wind energy.
The green certificates market in Belgium does not work well
due to the fact that the certificates cannot be exchanged
between the Regions. Moreover, there is no transparency
in the billing of the costs of green certificates to consumers. Given that the guaranteed minimum purchase price
for photovoltaic installations is higher than the market price,
the green certificates system means that the most efficient
technology in terms of costs for the production of green
energy has not been chosen.
Finally, in December 2010 the Management Board drafted a
proposal 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 201179. On
the basis of the limited quantity of gross energy included
in the 2008-2011 tariffs proposal and revised by the structural fall in the offtake of DSOs, the Management Board
proposed setting the surcharge at € 0.7820/MWh for 2011,
i.e. a proposed amount six times higher than the amount
of the surcharge for 2010. The main reason for this increase
may be attributed to the actual start-up of the 55 Belwind
offshore wind turbines in the North Sea. This amount was
laid down in the Ministerial Decree of 21 December 201080.
Cogeneration plants
At the request of the Minister for Energy, the Management
Board conducted a study on the advisability of extending
federal measures relating to a guaranteed minimum price
for green certificates as laid down in the Royal Decree of
16 July 2002 to include high-quality cogeneration plants
connected to the transmission system81. In this study, the
Management Board notably reached the conclusion, that
extending the aforementioned federal support mechanism to cover the concept of a ‘cogeneration certificate’
would constitute an infringement of the sharing of powers
between the Federal State and the Regions, as provided for
in Article 6, § 1, VII, paragraph one of the special Act of 8
August 1980 on institutional reforms.
76 Study (F)100128-CDC-944.
77 Study (F)100429-CDC-966.
78 The non-profitable portion of an investment is the balance (difference between the costs and the revenue) necessary to reach the minimum return put forward.
79 Proposal (C)101208-CDC-1006.
80 Ministerial Decree of 21 December 2010 setting the surcharge to be applied by the grid operator to offset the real net cost resulting from the obligation to buy and sell green certificates in 2011
(Belgian Official Journalof 27 December 2010).
81 Study (F)100415-CDC-961.
35
time, Belpex and APX 73% of the time. Belgium was isolated from the other two markets for just 1.2% of the time.
Extending nuclear power plants
The Act of 31 January 2003 on the gradual withdrawal from
nuclear energy for the purpose of industrial electricity generation provides for the gradual deactivation of nuclear power
plants as of 2015. In October 2009, the Belgian government
concluded a memorandum of agreement with the GDF
SUEZ group concerning the ten-year extension of the useful
life of the three oldest nuclear plants. The CREG had already
questioned the legal validity of this memorandum of agreement in a study dated 29 October 2009.
Owing to this high level of market coupling, on average the
prices are relatively similar. This may be seen from the figure
below: since market coupling has been in effect, the average monthly prices on the short-term market in Belgium,
The Netherlands and France have followed the same trend
and stayed at the same level (with the exception of certain months in 2007 and the month of October 2009 when
considerably higher levels were seen in France). Moreover,
it may be observed that the average prices on the wholesale
market are higher than in 2009. For example, the average
annual price on Belpex amounted to € 46.3/MWh in 2010,
compared with € 39.4/MWh in 2009.
The CREG notes that, whereas the signatories to the agreement had undertaken to carry out actions or undertake
certain acts within eight months of its conclusion, i.e. by
21 June 2010 at the latest, some of these actions have not
been taken. The question now also arises of whether or not
this agreement has been unilaterally annulled by the failure
to comply with the commitments made and even by decisions contrary to these commitments.
On 9 November 2010, the trilateral market (France, Belgium,
The Netherlands) was coupled to the German electricity
market. This coupling, known as the CWE coupling, was
coupled to the Scandinavian market at the same time using
another method. As a result, prices in the four countries of
the CWE region converged in November and December.
As at 31 December 2010, the Act on the gradual withdrawal
from nuclear energy had not yet been amended or repealed.
As such, the first nuclear power point remains scheduled to
be shut down in February 2015.
The total volume traded on the Belpex DAM stood at 11.8
TWh in 2010, with electrical power demanded by the Elia
network excluding pumped storage amounting to 84.7 TWh
(source: Elia, provisional data, January 2011). The volume
traded on Belpex therefore represents approximately 14%
of the Belgian market. The total volume purchased on Belpex in 2010 reached 9.6 TWh and the volume sold 8.9 TWh.
This difference is explained by this very market coupling,
imports from France and The Netherlands and exports to
these countries.
D. Energy exchange
The coupling of the Day-Ahead markets between Belgium
(Belpex), The Netherlands (APX) and France (EPEX FR) – trilateral coupling – once again proved successful in 2010: the
three markets only seldom operated in total isolation from
one another. Belpex and EPEX FR were coupled 87% of the
Figure 11: Average price on the Belpex, APX and EPEX FR exchanges between 2007 and 2010 (in €/MWh)
100
90
80
70
60
50
40
30
Prix moyen Belpex DAM
200741,8
200870,6
200939,4
201046,3
20
10
Belgium
36
Netherlands
France
2010/11
2010/09
2010/07
2010/05
2010/03
2010/01
2009/11
2009/09
2009/07
2009/05
2009/03
2009/01
2008/11
2008/09
2008/07
2008/05
2008/03
2008/01
2007/11
2007/09
2007/07
2007/05
2007/03
2007/01
0
Source: Belpex, Elia, CREG
At the end of 2010, there were 35 players on the Belpex
DAM.
To assess the market properly, it is interesting to know the
physical volumes traded on the exchange between the market
players and the volumes exchanged bilaterally (OTC).
The sensitivity of the electricity price to additional volume
(the market depth) is an important factor. A Belpex study
of the year 2010 indicates that the average price reacted
by around 3.6% to additional offer of 500 MW, compared
with 4.8% in 2009. Market resilience therefore increased in
2010 compared with 2009. The average monthly market resilience however can fluctuate sharply, as can be seen from
Figure 12 below. This figure shows the relative market resilience between 2007 and 2010: relative resilience can reach
levels of up to 35% (May 2007). In 2010, on the other hand,
market resilience remained below 10% throughout the year.
We also divided this trade into Intraday and Day-Ahead. Table 11
shows that in 2009 and 2010, the exchange accounted for over
a quarter of exchanges on the Day-Ahead market82. In 2010,
OTC Day-Ahead exchanges were virtually identical to those
in 2009. A large proportion of energy trading still takes place
outside the exchange. This also applies for Intraday exchanges
(Table 12), but to a lesser extent: 35% of Intraday exchanges
took place through the exchange in 2010; the share of OTC
exchanges fell sharply from 77% in 2009 to 68% in 2010.
Table 11: Breakdown of exchanges on the Day-Ahead hub
Since March 2008, Belpex has also organised an Intraday
exchange on which market players can exchange energy on
an Intraday basis. The table below shows the total volumes
exchanged in 2008, 2009 and 2010, as well as the prices.
The figures show that volumes increased in 2010 compared with 2009. The Intraday prices are higher than the DayAhead prices, mainly owing to the fact that there are more
Intraday transactions during peak hours, when prices are
inevitably higher.
Day-Ahead
Exchange
26%
OTC
74%
73%
Total
100%
100%
Intraday
2009
Exchange
2009
2010
Volumes (GWh)
89
187
275
Price (€/MWh)
87.7
42.3
50.1
27%
Table 12: Breakdown of exchanges on the Intraday hub
on the Intraday exchange
2008
2010
Source: Elia data, CREG calculation
Table 10: E
nergy exchanged and average price
Intraday
2009
2010
23%
35%
OTC
77%
65%
Total
100%
100%
Source: Elia data, CREG calculation
Source: Belpex data, CREG calculations
Figure 12: Average monthly resilience of the Belpex market in 2007-2010
30%
20%
10%
0%
-10%
-20%
-30%
Additional purchase of 500 MWh Additional sale of MWh
2010/11
2010/09
2010/07
2010/05
2010/03
2010/01
2009/11
2009/09
2009/07
2009/05
2009/03
2009/01
2008/11
2008/09
2008/07
2008/05
2008/03
2008/01
2007/11
2007/09
2007/07
2007/05
2007/03
2007/01
-40%
Source: Belpex, CREG
82 For exchanges on Belpex, half the volume is taken into account as Belpex always acts as intermediary and otherwise the volume would be counted twice.
37
E. Mergers and acquisitions
Figure 13: Trend in average all-in price for electricity
in 2009-2010 (in €/MW)
GDF SUEZ/International Power
On 29 November 2010, GDF SUEZ informed the European
Commission that it was taking over of International Power.
In response to a European Commission questionnaire received by the Management Board on 3 December 2010, the
Board issued a series of critical thoughts on this merger. As
at 31 December 2010, the European Commission had not
yet expressed its opinion.
F. Price trends
200,00
173.04
182.31
164.34
165.39
150,00
131.35 129.71
100,00
50,00
Price components
The final price billed to consumers includes a number of
components, namely:
1. the supplier’s price (energy);
2. the ‘renewable energy’ and ‘cogeneration’
contributions;
3. transmission (excluding public offtake);
4. distribution (excluding public offtake);
5. public offtake;
6. VAT and the energy tax.
The three tariff components that determine the main price
trends are, in order of importance:
1. the supplier’s price (energy);
2. the distribution tariffs; and
3. the energy tax and VAT (for household customers83).
The transmission tariffs, public offtake and the ‘renewable
energy’ and ‘cogeneration’ contributions are relatively less
important in the final price billed to the consumer.
0,00
Dc
(3.500 kWh/year)
lc
lc1
(160.000 kWh/year, BT) (160.000 kWh/year, MT)
2009
2010
Source: CREG
Household customers
In January and October 2010, the Management Board carried out two studies on the price components of electricity
and natural gas assessing, amongst other things, the trend
in the electricity price billed to the end customer since 2003,
so as to establish the contribution made by the various components to the development of prices84. The shares of each
component for a household customer are shown in the following graph.
Figure 14: Shares of the various components of the electricity
price for Gaselwest-Electrabel household customers
in 2010
The relative weight of the various components may vary
considerably between standard customers (consumer
profile and connection voltage), the distribution zones, the
regions and the suppliers. However, the distribution and
supplier price components account for approximately 70%
of all standard customers.
19%
33%
Energy
‘Renewable energy’ and ‘cogeneration’
contribution
3%
Transmission
Distribution (excluding public offtake)
Public offtake
2009-2010 trend
The price billed to the end consumer increased in August
2010 compared with December 2009. This increase is mainly due to the development of the parameters that make up
the supplier’s price. Moreover, a significant rise has been
seen in the federal contribution and the ‘renewable energy’
and ‘cogeneration’ contributions.
83 The VAT is deductible for business customers.
84 Studies (F)100107-CDC-934 and (F)101021-CDC-1004.
38
Energy tax and VAT
4%
37%
4%
Source : CREG
The graph below shows that the price for household end
customers rose in 2010 compared with 2009.
Figure 15: Trend in total electricity price – household customers (Dc)
230
220
210
200
€/MWh
190
180
170
160
150
140
130
Jan 07
Apr 07
Jun 07
Electrabel
Luminus
Lampiris
Oct 07
Jan 08
Apr 08
Jun 08
Oct 08
Jan 09
Apr 09
Jun 09
Oct 09
Jan 10
Nuon
Essent
Apr 10
Jun 10
Source: CREG
After the sharp rise in electricity prices in 2008 and the collapse that followed in 2009 (caused primarily by the economic crisis and its impact on the commodities markets),
electricity prices rose again in 2010.
This increase was due mainly to the development of supplier price indexes. The extent of the increase depends
on the supplier. Moreover, the unit price for free kWh fell,
representing a smaller discount for customers in Flanders.
Figure 16: Trend in the price of energy per supplier – household customers (Dc)
140
130
120
€/MWh
110
100
90
80
70
60
50
Jan 07
Apr 07
Electrabel
Luminus
Lampiris
Jun 07
Oct 07
Jan 08
Nuon
Essent
Apr 08
Jun 08
Oct 08
Jan 09
Apr 09
Jun 09
Oct 09
Jan 10
Apr 10
Jun 10
Source: CREG
39
It may also be noted that the contribution for renewable
energy and cogeneration is rising among all suppliers. This
is due to the increased obligation in terms of certificate quotas to be issued. Finally, the federal contribution has risen
by € 1.6/MWh.
Figure 17: Trend in the energy price per supplier – business customers, average voltage (Ic1)
140
130
120
€/MWh
110
100
90
80
70
60
50
Jan 07
Apr 07
Electrabel
Luminus
Lampiris
Jun 07
Oct 07
Jan 08
Apr 08
Jun 08
Nuon
Essent
Business customers
The development of the energy price billed for low voltage
by a supplier is identical for business customers and household customers. For average voltage customers, Electrabel
and Luminus base their prices on different indexation parameters than for low voltage. The trend in energy prices for
average-voltage customers therefore varies along different
lines to low voltage.
Over the course of 2010, the Management Board also carried out a study into the supply of electricity to consumers
with an offtake point in Belgium whose annual consumption
is higher than 10 GWh, or who require power in excess of
5 MW85. The purpose of this study was to identify the factors behind the energy price trend between 2008 and 2009
in this market segment.
The Management Board noted that there are substantial differences between the unit prices billed to major industrial
85 Study (B)101208-CDC-1025.
40
Oct 08
Jan 09
Apr 09
Jun 09
Oct 09
Jan 10
Apr 10
Jun 10
Source: CREG
customers. These differences cannot be explained solely
by the volume of consumption recorded. The Management
Board noted that various price setting mechanisms existed
side by side in 2009, which may shed light on the price differences observed. This situation may be attributed to the
various dates on which the mechanisms came into force, as
well as the different lengths of supply contracts. The price
setting mechanisms used before the liberalisation of the sector also continue to exist alongside mechanisms introduced
recently by the suppliers “to correspond more closely to the
risk profile” of their customers. In the context of this analysis of energy price setting mechanisms, the Management
Board was able to measure the growing importance of the
use of the benchmark of the BP Power segment of the APXENDEX exchange. It was also able to note a tendency for
the energy price setting mechanisms proposed to become
more complex. Given mechanisms requiring an in-depth
knowledge of the energy markets, industrial customers are
obliged to surround themselves with external resources to
manage their electricity supplies.
3.2.2. M
easures aimed at preventing abuse
of a dominant position
The CREG is responsible for the constant monitoring of the
electricity market, both in terms of market functionning and
in terms of prices. In this context, in 2010 the Management
Board conducted a number of studies.
Study on the Belpex Day-Ahead Market and the use of capacity on interconnections with France and The Netherlands
during the year 2009
In February 2010, the Management Board carried out a study
on the Belpex Day-Ahead Market and the use of capacity on
the interconnections with France and The Netherlands during
200986. This study provides information in a concise form on
two important aspects of the Belgian electricity market which
are closely interlinked: interconnections with other countries
and the exchange of electricity on the Belpex DAM. This study covers prices and volumes on the three coupled markets
(Belgium, The Netherlands and France) and market shares
on the Belpex DAM. The results of explicit auctions of interconnection capacity, the use of this interconnection capacity
and the congestion rents on the interconnections are also
discussed in this study.
The results of explicit auctions of monthly capacity show
what the market players expect with regard to the way in
which prices in Belgium, The Netherlands and France will
develop by mutual comparison over the coming month. The
differences in monthly prices expected by the market seem
to have forecast the real price differences between the three
countries in 2009 with a fair degree of accuracy. October
2009 is an important exception to this, when the market forecast a slight price difference (< € 1/MWh) between France
and Belgium, whereas in fact France was € 23.7/MWh more
expensive. Nevertheless, the analysis of the market shares
and price setting of buyers reveals that no market player was
able to forecast this huge difference in price.
The study also shows the importance of market coupling for
the Belgian electricity exchange. Over a nine-month period in
2009, 30 to 70% of the volume traded on the exchange was
exported. One of the consequences was that Belgium exported net electricity in 2009. The electricity exchange and the
market coupling have relatively substantial interconnection
capacity due to the fact that monthly and annual capacity holders resell this capacity on the electricity exchange using the
secondary market mechanism. At least 60% of the monthly
and annual capacity is resold in this way.
Finally, the Management Board study shows that the Belpex
Intraday market clearly traded more volume in 2009 than in
2008 (mainly with an increase in the volume traded during
the night). The prices on the Intraday market are on average
slightly higher than the prices on the Day-Ahead market.
Studies on the impact of the CO2 emission quotas system
on the electricity price
In June 2010, the Management Board updated studies
conducted in 2006, 2008 and 2009 on the impact of the
system of CO2 emission quotas on the electricity price in
Belgium87. Given the data available, and using a methodology based on the calculation of marginal costs, the Management Board noted that the selling price of electricity allowed
the partial or full integration of the carbon opportunity cost
of the marginal generating unit. On the wholesale market,
the increase applied in this way to all the kWh generated for
the Belgian market enabled electricity producers connected
to the Belgian transmission system to make a windfall profit
which may be estimated at €1,680 million over the 20052009 period. On the other hand, the analysis of the price
trend on the retail market shows that the opportunity cost
of the emission quotas was not apportioned in the selling
price applied on this market.
Taking the Management Board study as a basis, the national
Belgian railway operator brought an action against Electrabel
for abuse of its dominant position. In its judgment of 20 September 2010, the Court of First Instance in Brussels did not
call into question the objectivity of the study conducted by
the Management Board, but did cast doubt on the reasoning
of the Belgian Railway company. The court felt that the Belgian Railway company had not provided sufficient proof to
substantiate this abuse of power and dismissed its claim.
Studies on the nuclear issue
n
tudy on the structure of the cost of generating electricity
S
by the nuclear power plants in Belgium
This study was conducted by the Management Board in
May 201088 further to the twofold request from the Minister
for Energy relating on the one hand to the examination of
the structure of the costs of generating electricity at the nuclear power plants in Belgium and on the other hand to the
estimate of the monopolistic profits the producers record
on their nuclear activities.
First of all, the study outlines the theoretical framework of
the various concepts of costs, making a clear distinction
between the concept of direct production costs (fixed costs
and variable costs) and the concept of external costs linked
to the production process.
86 Study (F)100218-CDC-947.
87 Study (F)100610-CDC-974.
88 Study (F)100506-CDC-968.
41
The study subsequently goes on to present an analysis
of the structure of the costs of the Belgian nuclear power
plants, and an estimate of the average cost of generating
electricity using a nuclear source (€/MWh), by first recalling
the underlying working hypotheses. In this respect in particular, the analysis covers only the 20007 operating year,
bearing in mind the reliable information available to the
CREG when the study was produced.
To do so, the average production cost was estimated and
commented on, component by component, by means of a
successive analysis of the cost of the fuel, the operating
costs, the depreciation cost and the cost of provisions. The
operating cost was also broken down and commented on,
component by component: staff costs, insurance costs,
maintenance costs and administrative costs.
The analysis also shows that the estimated range obtained
for the average production costs for the year 2007 tallies
with results of international benchmarks. By comparing this
range of values for the average production cost with the
average forward wholesale price, it was also possible to
calculate an estimated range for the margin and the profit
recorded by the nuclear operator for the reference year.
Apart from the question of direct costs, the study also looks
at the issue of the external costs linked to nuclear power
generation on the basis of a review of the literature on this
matter. In this respect, particular attention was paid to the
European Commission’s draft on this issue, known as ExternE, so as to provide an estimate of this external cost.
n
tudy on comments about the article “Nuclear Market
S
Power: Taxation or Liberalization?”
This article89, one of the authors of which was Professor
Stefan Proost (K.U. Leuven), concludes that the national
social well-being would be better promoted by liberalising
the generation of electricity using nuclear power rather than
taxing it.
The Management Board wanted to respond to this article
by producing a study90 developing three arguments that
demonstrate that this conclusion does not apply to Belgium.
The first argument concerns the modelling of the electricity
market. This is based on the hypothesis that the market is
characterised by a dominant operator with exclusive access
to nuclear power generation, alongside of whom are competing producers with production capacities using sources
other than nuclear fuel. This modelling does not apply to
the Belgian market, however, in that the nuclear operator
in Belgium has a diversified production portfolio which also
includes thermal power plants, which in turn renders incorrect the issue of maximising the profit of the operator in the
nuclear sector alone. The maximisation of the profit recorded
by the operator should in fact concern the accumulated profit
made on the various types of production assets.
The second argument concerns the implementation of the
investments required to prolong the useful life of nuclear
power stations. In this article, this is considered to be a marginal cost, whereas in reality it should be considered as a
fixed cost. Now, this distinction impacts on the quantities
of electricity generated by nuclear power plants and hence
the result of the maximisation of the profit recorded by the
operator.
The third argument concerns the analysis of the national
well-being. This is incomplete in that it does not take account of the cost of installing new transmission capacities.
Moreover, the calibration of the model to the Belgian market
is open to discussion and the analysis does not take account
of the feasibility of the various scenarios considered.
As such, the aforesaid article cannot be used as a reference
to conclude that the that the Belgian market for electricity of
nuclear origin should be liberalised rather than taxed.
n
tudy on the impact of shutting down nuclear power
S
plants on the selling price of electricity to household end
customers
The Management Board also studied the impact of shutting
down nuclear power plants on the final price of electricity91.
This impact was calculated in the context of the current system, assuming that indexation parameters (Ne and Nc) and
the tariffs remain unchanged.
Two scenarios were simulated:
• the shutdown of the three oldest nuclear power plants:
Doel 1 and 2 and Tihange 1;
• the total shutdown of all nuclear power plants.
In both cases, the shutdown is presumed to have taken
place on 1 January 2010 and the calculations were made
for a representative average Dc customer (1,600 kWh day,
1,900 kWh night) supplied at the ESC Energy+ tariff.
This exercise indicated that the values of the parameter Nc
and the price of the power92, as well as the amount of the
total annual bill (€/year, including VAT) vary as follows depending on the scenario considered:
89 “Nuclear Market Power: Taxation or Liberalization?” by Pieter Himpens, Joris Morbee and Stefan Proost, available on http://www.idei.fr/doc/conf/eem/morbee.pdf.
90 Study (F)100708-CDC-978.
91 Study (F)100902-CDC-987.
92 The variations reported for the parameter Nc and the price of the power compared with the values observed for these two variables in the month of June 2010.
42
• in the event of the shutdown of the Doel 1 and 2 and
the Tihange 1 power plants: the Nc parameter would
increase by around 20%, the cost of the energy by
around 8%, and the total annual bill by around € 23
or 4%;
• in the event of the total shutdown of nuclear power
plants: the Nc parameter would increase by around
89%; the cost of the energy by around 38% and the
total annual bill by around € 103 or 19%.
n
tudy on the nuclear agreement in Germany and its appliS
cation in Belgium
The Management Board also produced a study examining
the nuclear agreement in Germany and its application in Belgium93. It was noted that this nuclear agreement consists of
two elements: on the one hand the launch of a legislative
initiative aimed at introducing a tax on nuclear fuel and on
the other hand the conclusion of a support fund contract
between the German government and the energy suppliers/
nuclear operators.
Under the terms of this agreement, the nuclear operators will
pay a contribution of € 15.19/MWh for the electricity generated from nuclear power plants for the 2011-2016 time frame
and € 9/WMh as of 2017. In total, the agreement will bring
in just over € 30,039 million. If the German provisions were
transposed in full to the Belgian nuclear park and applied in
exactly the same way, they would generate a sum of € 9,072
million. If they were only applied to the Doel 1, Doel 2 and
Tihange 1 plants, they would bring in € 2,247 million.
A degree of caution is appropriate when making a comparison with the Belgian memorandum of agreement. The
provisions differ substantially, particularly with regard to the
number of plants whose useful life is extended and the duration of this extension. When comparing the two countries,
it is also advisable to take account of the price of electricity
on the two markets, the cost structure and the depreciation
policy implemented.
Study on fixed-price contracts on the household electricity
and gas markets
At the request of the Minister for Energy, the Management
Board carried out a study that analyses the fixed tariffs available from suppliers operating on the Belgian electricity and
gas markets94. When the tariff is fixed, it remains unchanged throughout the period covered by the contract. It may,
however, be higher than the indexed tariff, given that it has
to cover the risk of cost fluctuations incurred by the supplier.
Despite the growing range of fixed tariffs available, the
share of active fixed-tariff contracts, although rising, remains very much a minority both on the electricity market
and on the gas market.
Two significant peak periods for two of the suppliers occurred
on the electricity market with the signing of new fixed-tariff
contracts: in November and December 2008 and between
April and June 2009. For gas, a single peak period was observed for one of the suppliers, between April and June 2009.
From July 2008 onwards, when electricity costs were
very high, new fixed tariffs for electricity were proposed.
These tariffs proved highly successful when they were first
launched, with customers having been caught out by the
sharp price rises wishing to lock in the price they would be
paying in the foreseeable future. A large number of contracts
took effect between September and December 2008. As
energy prices fell sharply thereafter, these customers fared
badly, facing a very high fixed price for the next two years.
In October 2008, two other fixed tariffs were launched
for green energy electricity contracts. For gas, the green
tariffs are identical. For electricity, of these two tariffs, oddly enough the higher tariff proved extremely successful.
Although this tariff offers additional advisory and technical
information services on saving energy, it is still unusual for
the more expensive tariff to prove the most successful,
even if its green nature is a selling point.
Study on the comparison of electricity prices for a household consuming 3,500 kWh of grey electricity (single tariff)
in Brussels, Paris, Berlin, Amsterdam and London
The aim of this study is to compare the electricity cost structure in June 2010 in Brussels with that of the capitals of various
neighbouring countries95. The customer in question is a household consumer with a single, rented meter, who uses 3,500
kWh of grey electricity a year, with a capacity of 6 to 12 kVA.
For each capital, the cost of the electricity is broken down
into the cost of the energy, i.e. the share of the supplier,
the cost of the transmission and distribution system, tax
and VAT. Three electricity supply contracts per capital were
chosen for the purpose of this breakdown. The first is that
of the default supply (Electrabel being the basic option in
Brussels), the second that of the most common commercial supply of the historic operator (Electrabel Energy+ in
Brussels) and the third the most widely used competing
supply (the Lampiris supply in Brussels). The weighted
average of these supplies on the basis of market shares is
93 Study (F)101014-CDC-999.
94 Study (F)100129-CDC-943.
95 Study (F)101007-CDC-995.
43
then calculated and this gives the price of electricity in the
capital.
As can be seen from the graph below, Brussels is the
most expensive capital after Berlin, where the cost of environmental policies is considerable, but only slightly so (€
741.33/year for Brussels compared with € 756.44/year for
Berlin). There are three reasons for this phenomenon: a
substantial energy cost – the highest after London, a very
high network cost and higher VAT than in the neighbouring
countries (21%). It should be stressed that the lack of competition on the Brussels market does not encourage any fall
in energy costs.
Study on the quality of the Nc parameter
In September 2010, the Management Board conducted a
study that analyses the quality of the Nc parameter96, the
parameter for the indexation of the price of electricity on
the household market. As the parameter was introduced in
the context of a regulated market, the aim of this study was
to determine whether the Nc is still representative of the
development of fuel costs and to identify any modification
to be made to guarantee its usefulness.
The Nc parameter is a Belgian monthly price index intended
to reflect the trend of fossil fuel (coal, gas and oil) and
nuclear fuel prices used to generate Belgian electricity. It
is currently used by three of the five suppliers who offer
variable tariffs.
Nc = 0.214 + 0.260 Ifnu + 0.375 Icoal + 0.240 Ioil +
1.195 (1-Ifnu) Ispotgas
This study showed that the majority of the reference values
making up the parameter formula established in 2002, are no
longer representative of reality. These values are:
• the composition of the generation park;
• the fuel costs;
• the reference values of the Infu, Iocal, Ioil and Ispotgas
indexes;
• the indexation of gas (on oil and coal);
• the new excises and contributions on energy.
The study subsequently goes on to establish that certain variables, which are essential if the parameter is to reflect the
trend in fuel costs, are not included in the Nc formula, i.e.:
• generation using biomass
• the cost of CO2;
• the costs of the Coo power plant;
• the substitution of nuclear power by coal
and purchases on Belpex.
Figure 18: Breakdown of the price of electricity in Brussels, Paris, Berlin, Amsterdam and London – June 2010 (€)
800
700
120.78 ; 16%
128.66 ; 17%
600
37.27 ; 5%
100.75 ; 16%
231.60 ; 31%
500
279.55 ; 38%
400
71.28 ; 11%
65.97 ; 14%
24.57 ; 5%
27.12 ; 5%
98.35 ; 19 %
180.95 ; 29%
59.69 ; 13 %
182.40 ; 24%
300
153.81 ; 34%
200
365.91 ; 71%
295.85 ; 40%
100
175.67 ; 39%
221.67 ; 29%
278.05 ; 44%
0
Brussels
VAT
Network
Taxes
Energy
96 Study (F)100909-CDC-948.
44
Paris
Berlin
Amsterdam
London
Source : CREG
Finally, new sources of supply are not taken into account
when calculating the price of electricity. These sources are:
•p
urchases on the Belpex and Endex exchanges;
• imports;
• s upplies from renewable energy sources.
The study concludes that it may be a good idea to think
about a new formula, similar to the current Nc, but that can
be adapted by each supplier depending on their fuel mix and
their supply strategy and therefore depending on their generation park, so as to enable each of them to use a parameter
that reflects their cost structure while retaining a single formula structure.
Having carried out this study on the quality of the Nc parameter and having analysed the answers from a supplier to
its questions about indexation parameters, the Management Board concluded that the representative nature of the
Nc, Ne and Iem indexation parameters was no longer ensured. The Management Board has therefore decided to cease
publishing these parameters as of February 2012.
Study on the feasibility of introducing “progressive tarification” of electricity in Belgium.
The question at the root of this study97, which was requested
by the Minster for Energy was whether progressive tarification was feasible and applicable in Belgium, bearing in mind
the legal aspects, the distribution of powers, the impact on
the various categories of revenue and experiences in other
countries, in particular those in Japan and California.
From a legal perspective, whether or not the measure is
acceptable under European law will depend on the motive
of general economic interest put forward to justify the measure and the terms and procedures governing its implementation. As regards Belgian law, progressive tarification must
be justified in terms of the rules on the division of powers.
If, for instance, the aim put forward to justify the introduction of progressive tarification is social in nature, then the
federal authorities will be competent. However, if the aim
put forward is the rational use of energy, then the regions
will be competent.
From an economic perspective, progressive tarification is
a second-choice solution. It must be accompanied by the
regulation of the price components and may lead to a reduction in consumption which may, if appropriate, prompt
a reduction in investments in the network, as is the case in
Japan and in California.
consumption level, drawn from major consumers. The Californian experience shows that the subsidy is, nevertheless,
insignificant, i.e. it only covers part of lifeline consumption,
owing to the inadequate elasticity of demand for electricity.
From an environmental point of view, the objective is to reduce consumption, thereby bringing down CO2 emissions.
However, this objective is conditioned by the elasticity of
demand for electricity. As this is poor, the reduction would
be limited.
The proposal put forward by the Management Board is to
establish twofold progressive tarification (with and without
electrical heating) combined with management of consumption by means of a time of use system that could be achieved using smart meters. Specific assistance will also have
to be provided for the implementation of progressive tarification, such as allowances for very low income households
with high consumption. This allowance would enable them to
renew their outdated, energy-guzzling electrical appliances.
Study on the possible impact of the electric car on the Belgian electrical system
The large-scale introduction of the electric car over the next
ten years seems possible. The expectation is therefore that
electricity prices will rise. A study conducted by the Management Board indicates, however, that the price of electricity on the wholesale market could fall compared with a
scenario that does not include the electric car98.
The battery would, in fact, be far too big for the average
daily distance travelled by car. Some of the battery capacity
would therefore remain unused. This unused capacity can
therefore be allocated to arbitrage on the wholesale market,
i.e. the purchase of electrical power at a low price (often at
night), the temporary storage of this power in the battery,
and resale thereafter, at peak times, which would make it
possible to shave peak prices. Electric cars could also be
used to maintain a balance in real time between supply and
demand for electricity. This would mean that intermittent
energy sources, such as wind and sun, could be integrated
more easily into the electricity grid thanks to the large-scale
presence of the electric car, without reducing grid security.
The battery is an important factor, however. If it is used
more intensively, it could wear out quickly. The degree of
wear of the battery depends largely on future technological
progress in car batteries, a field fraught with a considerable
element of uncertainty.
From a social point of view, the aim of progressive tarification is to give everyone access to electricity. This would
function by means of a subsidy, corresponding to the vital
97 Study (F)100610-CDC-972.
98 Study (F)100204-CDC-929.
45
4. Regulation and operation of the natural gas market
47
4.1. Regulation
4.1.1. M
anagement and allocation of the
interconnection capacity and congestion
mechanisms
High-calorific gas (market share 72%)
A number of cross-border interconnections face substantial
contractual congestion that affects both the Belgian market
and transit though Belgium. This is the case for the interconnection with the Dutch network in ‘s Gravenvoeren and the
Belgo-German interconnection in Eynatten. This contractual
congestion will be largely resolved as soon as the rTr2/VTN2
pipeline comes into service, scheduled for early 2011. The
commissioning of a new compression installation in Berneau
(end of 2011) and in Winksele (end of 2012) will also provide
sufficient capacity to meet Belgian and transit demand by
early 2013. By then, thanks to these investments, the Belgian H-gas market will have a single balancing point (reduction in the number of balancing zones from three to one).
Low-calorific gas (market share 28%)
The import capacity for L-gas has been frozen at its current
level since 2004 in accordance with the proposal in the indicative supply plan for natural gas drawn up by the CREG99.
This means that no investments are planned in Belgium
with a view to increasing the import capacity for L-gas, but
that the intention is rather to convert L-gas customers to Hgas as soon as the demand for L-gas exceeds the entry capacity available on the network. For this reason, the import
capacity faces at least contractual congestion and there is a
risk of physical congestion in the event of extremely wintry
conditions. It is important to mention that on the one hand
on the Dutch side of the interconnection at Hilvarenbeek
there is a serious risk of congestion owing to the Dutch
investment and capacity reservation policy which is based
exclusively on at least ten-year reservations and that on the
other hand, to date the reservation signs received from the
market for this Dutch capacity are lower than estimated
future consumption on the downstream networks. It is also
important to mention that the Belgian L-gas market is, to a
certain extent, supplied from France in backhaul at the Blaregnies/Taisnières cross-border point.
Transparency of information relating to the transmission
system
On 10 November 2010, the European Commission adopted
a decision amending the guidelines relating to the definition
of the technical information necessary for network users
to gain effective access to the network as established by
Regulation (EC) 715/2009100. This text, which comes into
force on 3 March 2011, when all the provisions of the third
European energy legislative package become applicable,
contains detailed requirements of both form and content
with regard to the information that TSOs will have to provide for network users so as to ensure effective access to
the grid. The system operators shall ensure that information
on availability and capacity use is published and updated
daily. They shall also have to publish detailed and complete
access regulations setting out the rights and responsibilities
of all grid users, containing information about the various
services provided and the different types of transportation
contracts available depending on these services.
In a liberalised and competitive market, effective access to
the grid in terms of transparency is vitally important. Detailed information about availability and use of capacity on the
grid will enable gas suppliers to identify and seize on market
opportunities in the short and long term. The need to improve the transparency requirements became even clearer
after the gas crisis in January 2009. These rules will contribute towards considerably optimising the use of available
grid capacity and will stimulate cross-border exchanges
between member states.
Capacity calculation methodology
The methodology used to calculate grid capacity is based
mainly on a detailed grid model and on flow and grid configuration scenarios. The grid model as such is very technical
and worked out on the basis of common practices. The grid
scenarios are left to the discretion of the TSO. Generally
speaking, peak scenarios are developed to simulate maximum technical capacity. The TSO is cautious and wishes to
ensure that the capacity offered to the market can be guaranteed under all circumstances. This means that in given
situations not covered by peak scenarios, this methodology
could give rise to a situation in which the maximum technical capacity is underestimated most of the time owing to
the stringent hypotheses adopted by the TSO. No European
directives exist making it possible to determine relevant
hypotheses for appropriate calculation of capacity.
Furthermore, the system operators do not always coordinate the grid capacity simulations. This is reflected, for
example, in the fact that the maximum technical capacities
on either side of cross-border interconnection points do not
match.
Another point is the fact that the technical and available capacities published are indicative and not binding on the TSO.
99 Proposal (F)040923-CREG-360 for the indicative supply plan for natural gas.
100 Decision 2010/685/EU from the European Commission of 10 November 2010 amending chapter 3 of Annex 1 to Regulation (EC)No 715/2009 of the European Parliament and the Council on the
conditions for access to the natural gas transmission networks, OJ (L) 293/67.
48
The Management Board also produced a study on the possible connection between the Dunkirk LNG terminal and the
Belgian natural gas transmission system. Details of this project are available under paragraph 5.2.4. of this report.
4.1.2. Regulation of transmission and distribution
A. Transmission and distribution tariffs
n
The agreement sets the entry/exit tariffs in accordance with
European legislation using a methodology underlying the
calculation of the tariffs based on costs that is the same for
both the transmission and transit of natural gas. The new
tariffs came into force on 1 January 2010 and will cease to
apply at the end of the current regulatory period, that is on
31 December 2011. The tariffs are among the most competitive in Europe, since the agreement introduces a reduction
of 28% in favour of grid users serving Belgian natural gas
consumers.
Transmission system (Fluxys)
The Royal Decree of 15 January 2010 made a few modifications to the methodlogy used to calculate the transmission
tariffs101.
In its ruling of 7 July 2010, the Constitutional Court, at the
request of the CREG, repealed the Amendment Act of 10
March 2009102 intended to include a specific tariffs system
for transit in the Gas Act. According to the Court, the principle of non-discrimination as enshrined in European legislation, implies a ban on subjecting access to the natural gas
transmission system to discriminatory terms. Consequently,
no distinction may be introduced between the transmission
of gas with a view to domestic consumption and transit. The
Court concluded that a national legal system that laid down
separated tariffs systems for transit and for the transmission of natural gas is not justified.
As regards the exceptions for historic transit contracts, the
Court considered that only the contracting parties specified
in the list attached to the 1991 European directive on natural
gas transit may possibly lay claim thereto, given that this list
should be considered exhaustive, including the entities in
charge of natural gas imports or exports.
Prior to the aforementioned ruling, the legislator had adopted an Act aimed at repealing the specific tariffs system for
transit on 2 March 2011103. The CREG has also filed a complaint against this Act.
b) Tariffs trend
During the last quarter of 2009, the CREG and Fluxys
concluded an agreement on the tariffs applicable to all transmission and storage activities for the years 2010 and 2011.
This agreement results from the application of Article 17, § 1
of the tariffs decree of 8 June 2007.
Thanks to the new tariffs, Fluxys will be able to fund its
huge investment programme (over € 1.5 billion over the
next five years), with a guaranteed fair return on the capital
invested.
n
Distribution network
During the previous regulatory period (prior to 2009), a costplus methodology was used. Under this system, the costs
of the DSO were checked by the CREG and increased by a
profit margin that enabled a fair return on capital invested
in the distribution network. In this system, the tariffs were
either approved by the CREG for the entire regulator period
(one year), or imposed by the CREG for three months.
On 1 January 2009, the former cost-plus regulation was
replaced by a methodology based on a guaranteed income
for the DSO, supplemented by cost-control incentives.
This new system guaranteed the network operator a total
income for a four-year regulatory period that is sufficient to
perform its duties as defined by law and provide a fair profit margin in return for the capital invested in the network.
During the aforementioned four-year regulatory period, the
following tariffs systems are possible:
• tariffs approved for the entire regulatory period if the
tariffs proposal accompanied by the network operator’s budget is approved before the start of the regulatory period;
• tariffs approved for the remainder of the regulatory
period if the tariffs are approved during this period;
• imposed tariffs in all other cases.
On 30 September 2008, all the DSOs submitted a tariffs
proposal with a budget for the 2009-2012 regulatory period
within the legal deadline. Since none of the proposals submitted was accompanied by the information requested, the
Management Board decided to reject the proposals and
101 Royal Decree of 15 January 2010 amending the Royal Decree of 8 June 2007 on the methodology for determining the total revenue comprising a fair margin, the general tariffs structure, the basic
principles on tariffs, procedures, the publication of tariffs, annual reports, accounting, cost control, revenue deviations of operators and the objective indexation formula referred to in the Act of
12 April 1965 on the transmission of gaseous and other substances by pipelines (Belgian Official Journal of 22 January 2010).
102 Act of 10 March 2009 amending the Act of 12 April 1965 on the transmission of gaseous and other substances by pipeline (Belgian Official Journalof 31 March 2009).
103 Act of 29 April 2010 amending the Act of 12 April 1965 on the transmission of gaseous and other substances by pipeline with regard to transit tariffs (Belgian Official Journalof 21 May 2010).
49
impose provisional tariffs. The provisional tariffs that were
imposed are based on the latest corresponding portions
of the total income approved by the Management Board,
i.e. the tariffs for the 2008 operating year. These provisional
tariffs remain in force for the entire regulatory period, until
all the arguments open to the CREG or the DSO have been
exhausted or until an agreement has been reached on the
points of contention between the CREG and the DSO.
In the course of 2009 most of the DSOs submitted new
tariffs proposals for the 2009-2012 regulatory period based
on the new reporting model. The tariffs of the mixed DSOs
(both the private and the public sectors have stakes in the
capital) of the operating companies Eandis (Flanders) and
Ores (Wallonia) have been approved for the 2009-2012
period, respectively as of 1 July and 1 October 2009. Like
Oers, the mixed DSO in Brussels, Sibelga, had its tariffs approved as of 1 October 2009. At the end of 2010, the CREG
reached an agreement with the four «pure» DSOs of the
Infrax operating company (Infrax West, Iveg, Inter-Energa
and PBE) on the points yet to be settled, such that they also
have approved tariffs as of 1 January 2011.
In its previous annual reports, the CREG already stressed that
the new regulatory framework leaves it little leeway to assess the reasonable and real nature of the costs put forward
by the DSOs. The CREG therefore remains convinced that
the legislation applicable to distribution tariffs needs to be
revised bearing in mind the third legislative package. The
transposition of this European directive offers the possibility
of adapting the current Belgian legislation on tariffs, amongst
other things in order to give the regulator the powers needed
to achieve more correct distribution tariffs.
50
b) Tariffs trend
Table 13 provides an overview of tariffs trends from 2008
to 2010. The provisional tariffs applied by DSOs have not
altered as the provisional tariffs for the 2009-2012 period
are identical to the tariffs in force for the 2008 operating
year. The 2009-2010 trend is considerably smoother than
the 2008-2009 trend and can be explained primarily by the
application of the indexation mechanism to manageable
costs and to a lesser extent to the development of other
elements, such as depreciation and non-manageable costs
(public service obligations, for instance).
Between the various DSOs, significant differences in tariffs
are seen to exist. These are explained on the one hand by
topographical and technical factors specific to the areas
supplied and on the other hand by the scope of the public
service obligations. Other factors such as the transfer of
balances from previous years (bonus/malus) also contribute
towards these differences in tariffs.
Table 13: Tariffs for the use of the distribution network in 2008, 2009 and 2010 (in €/kWh), excluding VAT
Household customer
23,260 kWh/year
Tariffs:
Approved: A
2008 Extended: E
€/kWh
GRD
ALG
2010
Δ
2010/2009
0.0100 0.0100
0.0100
0.00%
2008
E
Business customer
2,300 MWh/year
2009
2008
2010
Δ
2010/2009
0.0023
0.00%
2009
0.0023 0.0023
Industrial customer
36,000 MWh/year
2008
2009
0.0004 0.0004
2010
Δ
2010/2009
0.0004
0.00%
GASELWEST
A
0.0120 0.0135 (2)
0.0137
1.40%
0.0032 0.0034 (2) 0.0035
1.31%
0.0005 0.0006 (2) 0.0006
0.26%
IDEG
A
0.0129 0.0140 (3)
0.0148
5.06%
0.0036 0.0033 (3) 0.0035
5.10%
0.0008 0.0007 (3) 0.0008
3.66%
IMEA (IGAO)
A
0.0092 0.0090 (2) 0.0092
1.93%
0.0017 0.0015 (2) 0.0016
1.34%
0.0003 0.0002 (2) 0.0003
1.17%
IGH
A
0.0132 0.0147 (3)
1.41%
0.0037 0.0035 (3) 0.0036
0.57%
0.0006 0.0006 (3) 0.0006
1.79%
0.0027 0.0029 (2) 0.0029
1.09%
0.0006 0.0007 (2) 0.0007
0.80%
0.0149
IMEWO
A
0.0115 0.0129 (2)
0.0130
0.81%
INTERGAS
E
0.0073 0.0073
0.0073
0.00%
INTERGEM
A
0.0098 0.0117 (2)
0.0120
1.83%
INTERLUX
A
0.0136 0.0135 (3)
0.0146
7.86%
0.0051 0.0044 (3) 0.0046
5.72%
0.0011 0.0010 (3) 0.0011
4.66%
IVEG
E
0.0098 0.0098
0.0098
0.00%
0.0021 0.0021
0.0021
0.00%
0.0013 0.0013
0.0013
0.00%
pas applicable (1)
0.0024 0.0027 (2) 0.0028
pas applicable (1)
2.18%
0.0004 0.0005 (2) 0.0005
1.94%
IVEKA
A
0.0099 0.0116 (2)
0.0109
-5.94%
0.0023 0.0026 (2) 0.0025
-6.23%
0.0005 0.0007 (2) 0.0006
-6.09%
IVERLEK
A
0.0101 0.0111 (2)
0.0112
1.18%
0.0024 0.0025 (2) 0.0025
1.15%
0.0002 0.0003 (2) 0.0003
1.38%
0.00%
INTER-ENERGA
E
0.0146 0.0146
0.0146
0.00%
0.0030 0.0030
0.0030
0.00%
0.0017 0.0017
SEDILEC
A
0.0124 0.0137 (3)
0.0141
2.64%
0.0035 0.0034 (3) 0.0035
2.34%
0.0007 0.0007 (3) 0.0008
1.82%
SIBELGA
A
0.0128 0.0124 (3)
0.0133
6.95%
0.0037 0.0043 (3) 0.0045
4.85%
0.0018 0.0020 (3) 0.0021
6.42%
SIBELGAS N
A
0.0113 0.0137 (2)
0.0133
-3.07%
0.0032 0.0037 (2) 0.0036
-2.09%
0.0002 0.0003 (2) 0.0002
-3.03%
SIMOGEL
A
0.0085 0.0111 (3)
0.0115
3.20%
0.0016 0.0018 (3) 0.0019
2.26%
0.0009 0.0009 (3) 0.0010
2.52%
WVEM
E
0.0122 0.0122
0.0122
0.00%
0.0023 0.0023
0.0023
0.00%
0.0012 0.0012
0.0012
0.00%
0.0112 0.0121
0.0122
1.40%
0.0029 0.0029
0.0030
1.15%
0.0008 0.0008
0.0008
Average
0.0017
(1) Intergas does not have any business and industrial customers with over 1 GWh/year.
(2) Applicable as of 1 July 2009 (before this date, the 2008 tariffs applied)
(3) Applicable as of 1 October 2009 (before this date, the 2008 tariffs applied)
in Flanders in 2010
3,20%
1.02%
Source: CREG
in Brussels in 2010
5,58% 18,66%
2,13%
Network routing
Network routing
Meter hire
Meter hire
5,95%
Surcharges
Surcharges
2,34%
73,06%
89,08%
Source: CREG
Source: CREG
in Wallonia in 2010
5,45%
Network routing
13,77%
Meter hire
2,34%
Surcharges
78,44%
Source: CREG
51
c) 2009 balances
In 2010, the Management Board processed balances relating to the 2009 operating year. It should be noted that most
of the DSOs recorded a bonus on the management costs
and a malus on the non-manageable costs. The balance of
manageable costs is included in the income statement of
the system operator, while the accumulated balances of the
non-manageable costs relating to the 2008 to 2011 operating years are allocated by the Minister for Energy. When
processing the 2009 balances, particular attention was
made to go out to elements decommissioned by the DSOs
and a monitoring programme was used to check whether
the methodology proposed was observed and whether the
reported as having been decommissioned were actually
decommissioned both in the field and in administrative and
accounting terms.
d) Jurisprudence
In 2010, the Court of Appeal in Brussels returned a number of
rulings further to the regulatory vacuum found with regard to
its jurisprudence, under which the Royal Decrees of 2 September 2008 had been declared unlawful. In response thereto, the
legislator had, however, ratified the decrees in question (see
2009 Annual Report, pp. 28 and 51) but this did not alter the
fact that the decrees had been drawn up contrary to European
requirements in this field (more specifically the ban on arbitrary
modification of the proposal put forward by the regulator). Given
this situation, in a number of decisions the Management Board
decided that the CREG did not have a valid basis on which to
take decisions on tariffs.
tariffs have been in place for all Infrax members since 1 January
2011. The legal proceedings with Sibelga, the Brussels DSO,
have also been brought to a close and the tariffs have been
approved.
e) Studies
In 2010, the Management Board examined the development
of the kW term during the 2003-2009 time frame and in particular whether the importance of this term in the DSOs’ budgets (and consequently in the annual distribution costs for
the various standard customers) has increase or declined104.
As is the case for electricity, it may be concluded for natural
gas that the term kW developed along virtually the same
lines between 2006 and 2009105, both in comparison with
the tariff for transfer by the network and with regard to the
trend in the total annual costs of the distribution network,
and that consequently no notable alteration has occurred
between kWh and kW.
Moreover, the relative share allocated to the kW term compared with the total budget of a natural gas DSO has been
found to be considerably higher than for electricity. This phenomenon is explained by the fact that natural gas consumption
depends far more on the (outdoor) temperature than electricity
consumption. By maintaining the kW term, which is not linked to variations in atmospheric conditions and the resultant
consumption, at a high level, the tariff fluctuations are mitigated and this makes it possible to offer more stable tariffs.
B. Maximum prices
In a number of rulings handed down on 29 June 2010, the Court
of Appeal in Brussels rejected this point of view with respect to
the rules on establishing the value of the regulated assets. The
CREG was ordered to reach a new decision, in application of the
relevant provisions of the Royal Decree on tariffs.
These judgements were then extended in another series of rulings on tariffs decisions taken by the CREG, in which the Court
decided that the tariffs proposed by the DSOs were valid ipso jure.
The Court did, however, decide that it was not impossible that the
tariffs decisions had not been taken in accordance with the directives on certain points, but not to the extent that the Royal Decree
had to be rendered unenforceable in its entirety. The Courts specified that moreover there was no reason why the CREG should
not apply some of the specific provisions concerned.
In order to put an end to the constant insecurity, Infrax and the
CREG reached an agreement during the last quarter of 2010
concerning the tariffs to be applied during the last two years
of the 2009-2012 regulatory period. As a result, new approved
Price caps
A system of maximum prices has been implemented in Belgium for two categories of customers: protected end customers and unprotected end customers whose supply has
been terminated by the supplier.
The DSO ensures supplies to unprotected end customers
whose supply has been terminated by their supplier, at the
maximum price set as follows (Ministerial Decree of 1 June
2004 for electricity and 15 February 2005 for gas): energy
price + transmission tariff + distribution tariff + margin. The
DSO uses the tariffs data from these suppliers, with a minimum share of 3%, operating in its distribution zone, to the
extent that deliveries to household access points are in the
distribution zone. All the calculations include the suppliers
who deliver to at least 90% of the household access points.
In cases where a major supplier is active, but does not
provide 90% of the supplies for household customers, and
104 Study (F)101202-CDC-1020.
105 Given that the CREG only approved tariffs for natural gas as of 2004 and that examination has shown that the kW term was not used before 2006, the results indicated are limited to the 20062009 time period.
52
where all the other suppliers have a share of less than 3%,
it is consequently necessary to take account of the largest
of these small suppliers until 90% of household customers
are included in the calculation.
Excel file has been set up to be used by all DSOs to determine the calculation of the reference tariffs.
C. Code of conduct
The DSO and/or the supplier usually also take care of supplying protected end customers in accordance with federal
legislation (Ministerial Decree of 30 March 2007) at a maximum price set by the CREG which is valid for a period of six
months (cf. Articles 6 to 13). The supplier is compensated
for the obligation to supply at regular tariffs. The margin is an
amount which is added to the sum of the energy price, the
transmission and distribution tariff, 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, this 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.
Maximum prices applicable to dropped unprotected customers
The Management Board has decided to update, for both electricity and gas, the rules on the calculation of the maximum
prices applicable to unprotected customers whose supply
contract has been terminated106. This replacement was justified by three elements: the adaptation of the period for the
dropped customer tariff, the modification of standard customers and the standardisation of the method used to calculate
dropped customer tariffs.
With regard to the application period for the dropped customer tariff (reference tariff), there was a lapse of one month
between the maximum dropped customer tariff and the social tariff, which would cause needless complications when
calculating the claim. The decision taken by the Management
Board overcomes this problem by ensuring that the two halfyear periods coincide. These now run from 1 February to
31 July and from 1 August to 31 January.
As regards standard customers, the peak hour and off-peak
hour consumption of Dc and De customers had to be modified further to the extension of the night tariff to include the
weekend. The new annual consumption levels of these standard customers are now 1,600 kWh at peak times and 1,900
kWh at off-peak times for a Dc customer and 3,600 kWh at
peak times, 3,900 kWh at off-peak times and 12,500 kWh at
night only for De customers.
The standardisation of the model and the calculation method
became necessary owing to the significant disparity encountered until then in the presentation of reference tariffs and
the calculation methods used by the DSOs. The decision
taken by the Management Board means that a standardised
The Royal Decree of 23 December 2010 on the code of
conduct with regard to access to the natural gas transmission
system, the natural gas storage facility and the LNG terminal
was published in the Belgian Official Journal on 5 January 2011.
This new code of conduct, long awaited by players on the gas
market, came into being at the proposal of the CREG and was
drawn up in consultation with these players. It came into force
on the tenth day following its publication in the Belgian Official
Journal, that is on 15 January 2011.
The new code of conduct applies not only to the transmission
of gas intended for the Belgian market and to storage and LNG
activities, but also to border to border transit activities. It aims to
achieve transparent and non-discriminatory access to the transmission system, which should ultimately be beneficial for the
operation of the gas market and competition on this market.
D. Transmission model
On 24 September 2010, the Minister for Energy took the
initiative, in concert with Fluxys, to develop the role of Belgium as a natural gas hub for north-western Europe with a
view to guaranteeing the country’s security of supply.
The CREG supports this vision and had previously taken the
necessary initiatives proactively to put it into practice. For
instance, on 13 August 2010 the CREG launched a public
consultation process on the basic principles for a new transmission model. This model is one of the main elements
included in the new code of conduct that has been in force
since 15 January 2011.
The new code of conduct stipulates that the natural gas TSO
is to draw up a standard contract for the transmission of
natural gas (Articles 77, 96 and 109), a standard connection
contract (Article 96), access rules (Articles 29 and 111) and
a natural gas transmission programme (Articles 81 and 112).
The standard contracts constitute the ‘access ticket’ to the
transmission system, the transmission services and all the
information platforms provided by the natural gas TSO, for
shippers (standard natural gas transmission contract) and
customers (standard connection contract) alike.
The access rules include a detailed description of the transmission model used, all the operating rules and procedures
106 Decisions (B)100429-CDC-964 (electricity) and (B)100429-CDC-965 (gas). These decisions replace decisions (B)041202-CDC-384 (electricity) and (B)051124-CDC-490 (gas).
53
relating to access to the transmission services and subscription to these services, allocation rules, the nomination
and renomination procedure, provisions applicable in the
event of reductions and interruptions, the grid balance rules,
congestion management procedures, provisions applicable
in the event of maintenance, rules on pressure and quality,
the procedures for measuring the quantities and characteristics of natural gas and all the rules on the operation of the
secondary market and access to the hub.
In this context, the following in particular are submitted for
consultation:
The natural gas transmission programme contains a clear
description of the transmission model and serves first and
foremost as the catalogue of the natural gas transmission
services offered by the operator. Other than this, it describes
the reservation mode of natural gas transmission services on
the primary market and provides information on congestion
management and the operation of the secondary market.
If the current restrictions of the existing transmission model
are not eliminated in the near future, there is a risk that a
number of market players will be tempted to abandon the
Belgian natural gas market. Market players will turn their
attention to neighbouring natural gas markets, which are
more easily accessible and more liquid. A development like
this would not benefit Fluxys or Belgian end customers,
whether household or industrial.
Both the standard contracts and the access rules and natural gas transmission programme need to be submitted to
the CREG for approval by the natural gas TSO. These key
documents are drawn up after consultation with the market players concerned. To this end, the operator creates a
consultation structure (Article 108) intended to ensure regular and structured consultation with grid users.
The basis for drawing up the documents referred to above is
of course the transmission model used by the operator. The
current natural gas transmission model dates from 2004. It
has certainly proved its worth, but is no longer in line with
developments on the natural gas transmission market and
the modified European and Belgian regulatory context.
This transmission model has a number of specific characteristics which are now considered to be restrictive by many
market players, both for transmission and for the exchange
of natural gas. These restrictions need to be removed in
order to stimulate the subsequent development of both the
natural gas transmission services and the exchange market
and thereby guaranteeing security of supply.
Among these restrictions, with regard to the capacity allocation rules, it is worth mentioning:
• the coupling of entry and offtake points when reserving transmission services;
•
a series of complex allocation rules with matching
rules and allocation on the basis of priorities in the
event of congestion;
• the inefficient use of certain entry points.
54
• the allocation of entry capacity with the aid of simple
and transparent allocation rules;
•
the independent reservation of entry and offtake
capacities;
• the proactive congestion policy with the aid of transparent and non-discriminatory rules drawn up in advance.
Moreover, these restrictions have direct consequences for
the electricity market. The rapid development of decentralised electricity generation, the growing importance of solar
and wind energy and the role of natural gas as a back-up
make easy and fast access to the natural gas market (both
transmission and trading) absolutely essential.
If Belgium is keen to uphold its security of supply and its
position as a major hub for the transmission and exchange
of natural gas in north-western Europe on a lasting basis in
the years to come, then reorienting the natural gas transmission market is definitely a priority.
The new code of conduct adopted at the proposal of the
CREG stipulates that the natural gas TSO devises a transmission model intended in particular for the independent
reservation of entry or offtake capacity, the use of a single
balancing zone, the stimulation of the operation of the secondary market for natural gas transmission services and
the stimulation of liquidity on the natural gas market (Article
113). The operator is developing the natural gas transmission
services needed to achieve this end.
In the meantime, the CREG has analysed the results of this
consultation on the transmission model and in January 2011
it published the consultation report on its website, together
with a staged plan designed to lead to the introduction of a
transmission model by the end of 2012.
E. Indicative transmission programme
Routing
In 2011, a new gas transmission programme (formerly
known as the “Indicative Transmission Programme’ or ITP) is
to be drawn up to take account of the new code of conduct,
the new services developed by Fluyxs and the feedback on
the subscription period (capacity congestion management).
While awaiting the new code of conduct, in 2009 Fluxys
had already introduced an ITP for the 2010-2011 period in
accordance with the old one.
The programme of services proposed for the transmission
of gas comprises a detailed description of the gas transmission model used and the various transmission services
offered by the TSO. Amongst other things, this includes a
practical description of the allocation rules used, the balancing service, the means of subscribing for services, in particular via the Automatic Reservation System or ARS, the
rules on congestion and the working of the secondary market via the Secondary Market Platform (SMP). In the first
phase, the TSO devises the transmission model with a view
to achieving maximum synergy between internal transmission and transit, the independent reservation of entry and
offtake capacity and the promotion of the operation of the
secondary market. In a second phase, once the investments
being made by the TSO lead to a single balancing zone, the
gas transmission programme will need to be amended by
the TSO along these lines.
This ITP was approved by the Management Board on 29
October 2009 for the 2010-2011 period.
On 14 January 2010, the Management Board approved an
initial modification to this ITP with regard to the MBT category of customers (customers who benefit from a lower
tariff). In fact, it was advisable to put an end to the existence
of this service (and therefore the related tariff reductions)
given the new tariffs for the Fluxys transmission activity and
storage activity approved by the CREG on 22 December
2009 for the years 2010 and 2011.
After this, on 1 April107 and 1 June 2010108, the Management
Board approved a second and third modification to the ITP
so as to specify the description of the characteristics of
the Fluxys entry-exit system (previously described as Enhanced), refine the allocation of flexibility services (HIT, DIT,
CIT), and introduce the “capacity pooling @ supply point”
service.
On 23 November 2010, Fluxys introduced a new ITP for the
2011-2012 period. A major change has been made to the
rules on congestion and allocation involving the scrapping of
the subscription period. The new ITP was approved by the
Management Board on 8 December 2010.
Storage
On 12 May 2010, the Management Board approved the
indicative transmission programme for storage for the 20102011 period109. It contains a number of important new features with regard to allocation, flexibility and information.
The main change relates to the introduction of new storage
service allocation rules. The rules currently in force do not
take account of subsequent changes in the market share of
grid users. This is why the Management Board asked Fluxys
to draw up new rules. The methodology adopted by Fluxys
is based on the future market shares of storage users. For
each storage user, a priority right is calculated and allocated to these users based on their capacity subscriptions on
the gas receiving stations (GOS) for the following storage
period. Each one is allocated a weighting factor per month
that takes account of the total capacity subscription to the
storage services by all the grid users for the month in question. The allocation is undertaken in two stages. An initial
allocation begins on 15 April of the year in question on the
basis of the priority rights calculated on 1 March.
A second major modification relates to the offer of flexibility services. The Management Board has already voiced its
concerns on repeated occasions about the limited supply
of flexibility services for storage in general and the lack of
short-term storage services in particular. In order to comply
with its undertaking in this area, the transmission company
has drawn up a proposal for short-term services based on
the virtual storage concept. The formula used to calculate
the allocated right takes account of the concern of the
CREG to simplify access to the grid for smaller newcomers.
A third major modification relates to the information that the
transmission company has to provide for grid users. Further
to the request from ERGEG, the CREG asked Fluxys if it
was ready to move from the weekly publication of a number
of relevant parameters relating to gas storage to the daily
publication of these data, supplemented by some additional
information as of 30 November 2009. Fluxys said it was prepared to publish the daily allocations requested concerning
the injection, emission and quantity of gas in storage both
at the Loenhoet storage facility and at the Dudzeel peak storage facility on a daily and aggregate basis. Moreover, it also
considered the deadline to be realistic. In accordance with
107 Study (F)100401-CDC-960.
108 Study (F)100617-CDC-973.
109 Decision (B)100512-CDC-969.
55
the indicative transmission programme for storage services
covering the 2010-2011 period, the data in question will be
published on a daily basis using the EASEE GAS standard.
The new programme also states that the marketing of services linked to the transportation of LNG by tanker from the
terminal to the Dudzele storage facility will be undertaken
by Fluxys rather than by Fluxys LNG as of the 2010-2011
season.
The CREG asked Fluxys to submit a new proposal for the
2011-2012 period by 30 June 2010 at the latest and to take
address the comments made in the decision on the 20102011 proposal in its new proposal.
On 30 June 2010, Fluxys submitted an initial proposal for
an indicative storage programme covering the 2011-2012
period. As it had not yet received reservations for the virtual storage service, on 20 December 2010 Fluxys submitted a final proposal for the Indicative Storage Services
Programme 2011-2012 to the CREG on 20 December 2010.
4.1.3. Effective unbundling
Appointment of transmission system, storage facility
and LNG terminal operators
Since 2006 Fluxys, together with Fluxys LNG, has in fact
undertaken the management of transmission on the natural gas transmission system, the storage facilities and the
Zeebrugge LNG terminal. In February 2007, the Minister for
Energy initiated legal proceedings aimed at appointing three
system operators for a period of twenty years by means of
a ministerial decree.
On 17 December 2009, the CREG issued positive opinions
for the appointment of Fluxys as operator of the natural gas
transmission system and storage facility and the appointment of Fluxys LNG as operator of the LNG facility.
On 23 February 2010, Fluxys was finally appointed by the
Council of Ministers as the operator of the natural gas
transmission system and storage facility and its subsidiary,
Fluxys LNG, as the operator of the LNG facility.
Terminalling
Unbundling of the TSO
A new LNG programme (formerly known as the LNG ITP) is
to be drawn up to take account of the new code of conduct
and the services developed and offered by Fluxys LNG.
However, while awaiting this new code of conduct, on 30
June 2010 Fluxys LNG submitted an LNG ITP for the 20112012 period in accordance with the old one.
In fulfilment of the commitments offered in 2006 by GDF and
SUEZ as part of their merger, an initial share transaction was
undertaken in 2009 between GDF SUEZ and Publigaz (whereby Publigaz exercised its pre-emptive right). On 18 May
2009, the Competition Council approved the Publigaz/Fluxys
merger. The actual merger went ahead on 27 May 2009.
On 30 September 2010, the Management Board approved
this LNG ITP from Fluxys LNG for the 2011-2012 period110. In
this ITP, the loading capacities of the LNG road tankers are
again marketed by Fluxys LNG given the decision taken by
Fluxys to close the peak shaving plant in Dudzele further to
the termination of capacity reservation at this facility by the
only shipper involved.
F. Standard connection contract
An Act that was published in the Belgian Official Journal on
8 December 2009112 stipulated that the suppliers or their
affiliated companies are permitted to hold no more than
24.99% of the capital or voting shares in a transmission
infrastructure operator, by 31 December 2009 at the latest.
Nor may the memorandums of association of the transmission infrastructure operator and the shareholders’ agreements grant special rights to producers, suppliers or their
affiliated companies. This Act obliged Electrabel to transfer
at least 13.51% of its stake in Fluxys.
On 21 January 2010, the Management Board approved the
proposal, which had been reworked (again) and submitted
by Fluxys for the standard contract for the connection of
end customers to the natural gas transmission system111. In
its decision, the Management Board drew attention to the
circumstances in which the standard connection contract
will need to be reassessed and adapted where appropriate.
Further to this modification of the legal context, in March
2010 GDF SUEZ and Publigaz concluded an agreement
concerning the transfer to Publigaz of the entire Electrabel
stake in Fluxys (38.5%). The transaction was carried out on
5 May 2010. Further to this transaction, the Publigaz stake
in Fluxys increased to 89.97%, while GDF SUEZ withdrew
entirely from the Fluxys capital.
110 Decision (B)100930-CDC-989.
111 Decision (B)100121-CDC-939.
112 Act of 10 September 2009 amending the law of 12 April 1965 on the transmission of gaseous and other substances by pipeline (Belgian Official Journalof 8 December 2009).
56
This agreement also states that the GDF SUEZ group transfers to Fluxys its 6.8% stake in Fluxys. Since 5 May 2010,
Fluxys LNG has therefore been a wholly-owned subsidiary
of Fluxys.
In fulfilment of the above, the memorandums of association of Fluxys have been modified (see publication in the
annexes to the Belgian Official Journal of 30 April 2010).
In a press release Fluxys announced that under the terms
of the same agreement, the 5% stake of the GDF SUEZ
group in Interconnector (UK) Ltd will also be transferred to
Fluxys NL as soon as the formalities have been finalised
with the shareholders of Interconnector (UK) Ltd. Further to
this transaction, the share of the Fluxys group in Interconnector (UK) will rise to 15%.
Figure 22: Shareholding body of Fluxys as at 31 December 2010
Independence of the system operator – corporate
Governance
As it does every year, in 2010 the CREG examined and
commented on the activity report of the Fluxys Corporate
Governance Committee for the year 2009 (monitoring of the
application of Article 8/3 of the Gas Act, assessing efficacy
with regard to the requirements in terms of independence
and impartiality of directors as stated in the code of conduct.
It questioned Fluxys about the composition of the group of
independent directors as regards their know-how. In fact,
the latter are chosen partly for their know-how in the field of
financial management, partly for their useful technical knowhow and mainly for their relevant know-how of the energy
sector. At the end of 2010 the CREG had not yet completed
this analysis.
In 2010, the CREG did not issue any binding opinion about
the appointment of independent directors at Fluxys.
PUBLIGAZ
100% *
4.2. Competition aspects
* Fluxys Finance holds
1,000 shares out of a total
of 60,934,737 shares
in Fluxys G.
4.2.1. Description of the wholesale market
Fluxys G
89.97%
(6.68% of which
are listed)
10.03%
NYSE Euronext Brussels
secondary market
(+ 6.68% listed shares held
by Publigaz)
1 share
Specific share
of the Belgian state
Source: Fluxys website
A. Natural gas supplies
Natural gas suppliers can choose from among a series of
entry points on the natural gas transmission system to
supply their Belgian customers with H-gas. Natural gas
customers who use L-gas are supplied from The Netherlands or indirectly in backhaul via the Blaregnies interconnection point with France. LNG supplies, mainly from
Qatar via the Zeebrugge terminal, accounted for a share of
6.2% of Belgian natural gas consumption in 2010, compared with 9% in 2009. With a share of 46.5%, Zeebrugge
has once again consolidated its position as the gateway
to the Belgian market. The sharp increase in the importance of Zeebrugge (in 2009 its share was considerably
smaller, at 38.3%) is due to the rise in suppliers via shortterm transactions at the Zeebrugge hub, prompted by two
factors: the relatively high price of natural gas contracted
in the long term and the increase in the number of new,
relatively small suppliers who prefer short-term supply
contracts. For the L-gas market, we have observed fairly
substantial supplies in backhaul from Blaregnies (4.9% in
2010 compared with 2.6% in 2009) on the transit flows
initially intended for the French market. This observation
reflects the issue of capacity availability and allocation at
the Hilvarenbeek/Poppel interconnection point on both the
Dutch and the Belgian side.
57
Figure 23 : B
reakdown of supply per entry zone in 2010
Blaregnies* (H-gas)
4,3%
Blaregnies* (L-gas)
4,9%
East (Eynatten)
4,1%
West (Zeebrugge)
46,5%
North-east
(‘s Gravenvoeren, Dilsen)
10,7%
Spot transactions (especially on the Zeebrugge hub) rose
sharply from 18.4% in 2009 to 24.7% in 2010, as did supplies via contracts of more than one year concluded on the
wholesale market, which rose substantially from 5.2% to
9.4%. This may be attributed to the same reasons as those
that explain the use of access points: relatively lower natural
gas prices on the wholesale market compared with longterm contracts concluded with the producers, as well as
the steady growth in suppliers starting out on the Belgian
market.
North (L-gas)
21,4%
North (Zandvliet)
1,9%
LNG terminal
6,2%
* The Blaregnies entry points are used “in backhaul“ to the actual flows (reverse flow), making
use of the predominating transit flows at these points.
Source: CREG
Figure 24: C
omposition of aggregated supply portfolio
of suppliers operating in Belgium in 2010
Other contracts < 1 year
24.7%
Contracts with producers > 5 years
60,3%
Other contracts > 1 year
9.4%
Contracts with
producers < 5 years
5,7%
Source: CREG
58
Overall, the individual supply portfolios of the various natural gas suppliers result in a differentiated supply depending
on the type of contract. The share of long-term contracts
concluded directly with natural gas producers has declined,
falling from 71.3% in 2009 to 60.3% in 2010, but still constitutes the main component. 2010 saw a shift towards supplies on the wholesale market.
B. Holders of a natural gas supply permit
The companies operating in the supply of natural gas on the Belgian market can be broken down as follows:
Table 14: Companies operating in the supply of natural gas on the Belgian market in 2010
Volume routed in 2010 (TWh)
Company
Domestic
market
Date of
permit
Domestic
market
Belgium*
Elsewhere
Total
Market share
in Belgium**
E.On Ruhrgas A.G.
Germany
30.03.07
526.1
0
167.5
693.6
0%
Distrigas S.A.
Belgium
02.03.09
n.d.
112.1
n.d.
n.d.
52.1 %
France
26.05.09
n.d.
39.3
n.d.
n.d.
18.3 %
United Kingdom
13.06.07
5.57
0
4.91
n.d.
0%
Germany
03.09.07
184.0
10.6
11.0
205.6
4.9 %
Netherlands
02.11.07
88.9
1.25
0
90.1
0.5 %
France
31.01.08
0
0
0
0
0%
Belgium
01.10.08
n.d.
0
0
n.d.
0%
0.7 %
GdF Suez
Total gas & Power North Europe Ltd.
WINGAS GmbH & Co KG
RWE Supply & Trading Netherlands B.V.
Gaselys S.A.S.
Nuon Belgium S.A.
Vattenfall Energy Trading Netherlands N.V.
Netherlands
04.11.08
63.5
1.55
4.0
67.5
Electrabel Customer Solutions S.A.
Belgium
18.09.03
0
0
0
0
0%
SPE S.A.
Belgium
12.03.07
-
18.87
0
18.87
8.8 %
Electrabel S.A.
Belgium
16.03.04
0
19.14
0
0
8.9 %
France
29.11.05
n.d.
0
n.d.
n.d.
0%
Belgium
29.11.05
n.d.
2,35
n.d.
n.d.
1.1 %
EDF S.A.
EDF Belgium S.A.
Essent Belgium S.A.
Merril Lynch Commodities (Europe) Ltd.
Statoil ASA
Belgium
29.11.05
n.d.
0
n.d.
n.d.
0%
United Kingdom
09.06.06
n.d.
0
n.d.
n.d.
0%
Norway
28.09.09
n.d.
3.72
44.5
n.d.
1.7 %
Netherlands
16.07.07
n.d.
1.06
n.d.
n.d.
0.5 %
E.On Belgium S.A.
Belgium
03.09.07
0
0.05
0
0.05
0.02 %
Delta Energy B.V.
Netherlands
02.11.07
n.d.
0
n.d.
n.d.
0%
Eneco België B.V.
Air Liquide Technische Gassen B.V.
Netherlands
20.12.07
n.d.
0
n.d.
n.d.
0%
ConocoPhillips Ltd.
United Kingdom
18.02.08
10.8
0
n.d.
n.d.
0%
Gazprom Marketing & Trading Ltd.
United Kingdom
18.04.08
160.9
0
8.4
n.d.
0%
Lampiris S.A.
Belgium
04.11.08
0
2.62
0
2.62
1.2 %
RWE Energy Belgium S.P.R.L.
Belgium
27.07.09
0
1.06
0
1.06
0.5 %
E.On Energy Trading S.E.
Germany
28.09.09
137.3
1.54
n.d.
168.5
0.7 %
United Kingdom
20.11.09
183.2
0
64.7
n.d.
0%
Energy Logistics and Services GmbH
Austria
13.04.10
n.d.
0
2.25
n.d.
0%
Gas Natural Europe SAS
France
12.05.10
n.d.
0
n.d.
n.d.
0%
natGas A.G.
Germany
27.08.10
23.2
0
0.72
23.9
0%
Progress Energy Services S.P.R.L.
Belgium
22.12.10
n.d.
0
n.d.
n.d.
0%
Exxon Mobil Gas Marketing Europe Ltd.
* T
hese figures only bear on the transmission market: supplies to customers connected to the transmission system and to offtake points on the distribution
networks. For separate statistics on supplies on the transmission and distribution markets, please consult the joint publication of the four energy regulators
at www.creg.be.
** Relates to the respective market shares of the holders of a supply permit for access to the transmission system, on the basis of the figures in the “Belgium”
column. These market shares are average values for 2010 and do not necessarily reflect the situation on 31 December.
Source: CREG
In 2010, total natural gas consumption113 rose to 215.3
TWh, up 10.9% compared with consumption in 2009
(194.2 TWh). This increase was the result of a considerable
rise in consumption by end customers connected to the
distribution networks (+ 15.5%) and consumption by industrial customers (+ 19.7%) on the one hand and more or less
stable consumption for the generation of electricity (and the
production of heat) (-0.3%) on the other.
113 It should be noted in this respect that the evaluation is based on figures linked to shipping activities on the transmission system as provided by the transmission system operator.
59
In 2010, four new players, Electrabel, RWE Energy Nederland, whose activities were taken over by its sister subsidiary
RWE Energy Belgium during the course of the year, Vattenfall
Energy Trading Netherlands and E.On Energy Trading began
to supply on the wholesale market for natural gas, which includes supplies to direct customers connected to the Fluxys
grid as well as supplies to distribution networks. As a result,
in 2010 a total of fourteen supply companies were operating
on the Belgian market.
marketing on the distribution networks by Electrabel Customer Solutions from Distrigas.
As at 1 January 2011, twenty-nine network users held a routing supply permit. Fourteen of them had actually reserved
capacity for the delivery of natural gas to the Belgian market
on the Fluxys network, compared with six at the end of 2007.
C. Natural gas transmission permits
The share held by Distrigas on the transmission market fell
sharply in 2010 to 52.1% The reduction amounts to -17.9
percent, which represents the biggest drop since the liberalisation of the market. GDF SUEZ has consolidated its position
as the second largest shipper on the market (+ 5.9 percent),
with a share of 18.3%. SPE continues to make progress and
gaines 1.9 percent, taking its market share to 8.8% Despite
its growth, SPE had to yield its third place to newcomer Electrabel. Electrabel attained a market share of 8.9% at a single
stroke, thereby stepping up to become the third largest shipper thanks mainly to its share in the electricity generation
sector. It is worth noting that as of the month of November
parent company GDF SUEZ took over the Electrabel routing
activities. The GDF SUEZ group holds a total of 27.2% on the
transmission market. Wingas is the second largest loser after
Distrigas (-1.1 percent) and has seen its market share fall to
less than 5%. Statoil also lost ground in 2010 (-0.2 percent
compared with 2009). Lampiris has a market share of 1.2%.
Among the other newcomers in 2010, Vattenfall Energy
Trading Netherlands, which operates only on the L-gas distribution network, has a market share of 0.7%, while RWE
Energy Belgium has slightly less than 0.5%, again mainly on
the L-gas distribution networks. E.On Energy Trading, which
started routing in the middle of the year, has reached a market share of 0.7%. Among the players with a (temporarily)
limited market share, that of EDF Belgium has risen by 0.2%
to 1.1%, while that of Eneco België has fallen by 0.2% to
0.5%. EDF Belgium transferred its commercial activities to
SPE on 1 October 2010. E.On Belgium has seen its market
share fall to just 0.02%. Essent Energy Trading, whose name
has been changed into RWE Supply & Trading Netherlands,
maintains its market share at 0.6%.
As expected, the consequences of the merger between GDF
and SUEZ strongly impacted on developments on the transmission market as of 2010. This can be seen in the activities
of Electrabel, which was taken over at the end of the year by
its parent company GDF SUEZ. Given that the activities of
Electrabel have provisionally been focused primarily on the
generation of electricity, it may be deduced that mutual relations between the market players will undergo further significant changes in the future. It is expected that GDF SUEZ
will partly take over the transmission of gas intended for
The CREG has the power to issue opinions on transmission
permits with regard to the transmission system. To build and
operate its natural gas facilities, Fluxys submits applications
for transmission permits to the Energy Authority in place
with the Federal Public Service of the Economy, SMEs, SelfEmployed and Energy. The CREG issues an opinion on this.
For applications that impact on the distribution networks,
the CREG consults with the regional regulators concerned.
In 2010, eleven Fluxys transmission permit applications were
passed on to the CREG for an opinion. A favourable opinion
was given in each case. The Management Board also returned three opinions on applications submitted in 2009.
D. Exchange platforms
Setting out from the work done in 2009, on 10 October 2010
ERGEG gave its final approval of the 2010 monitoring report
drawn up by the CREG on the “regulatory oversight of natural gas hubs”114. This report presents a series of conclusions
drawn from the analysis of gas hubs in Europe. The main
aim of this exercise was to compile a list of the various monitoring mechanisms on the European hubs. In addition, the
document puts forward a few recommendations intended
to improve surveillance and regulatory monitoring.
Moreover, the European Commission has drawn up a proposal for a regulation on the integrity and transparency of the
energy market (REMI). This proposal aims to introduce great
transparency on the market by imposing clear market rules
for energy traders. The wholesale markets such as the exchanges and hubs, where gas and electricity are exchanged
between producers and traders, take on more importance
in terms of the prices paid by end customers.
The new rules proposed relate to the identification and use
of “privileged” information on transactions that send out
incorrect and misleading signals to the market and on the
spreading of false rumours that give out misleading signals.
The task of monitoring these rules is to be entrusted to
ACER, the European Agency for the Cooperation of Energy
114 http://www.energy-regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_ERGEG_PAPERS/Gas/2010/E10-GMM-11-03%20Gas%20Hub%20Monitoring%20Report%20
2010_final.pdf.
60
Regulators. This agency is to work closely with the national
regulators, who bear joint responsibility for examining suspicious cases and who will have to impose penalties where
necessary.
For Belgium, this mainly concerns trading on the Zeebrugge
hub and the APX GAS ZEE gas exchange. While activity on
the gas exchange may be considered rather minimal (only
ten or so transactions in an entire year), Huberator, as
the hub operator, noted growing interest in 2010. Eightytwo companies are currently registered as members. And
while the total volume traded at the hub in 2010 remained
constant compared with 2009 (62 bcm or 742 TWh), churn
doubled in the last few months of 2010. The churn factor,
which represents the number of times the gas is traded before being physically taken elsewhere, proved to be higher
than 10 for the first time since the hub was created. Generally speaking, this is seen as a positive increase in liquidity
in short-term trade. In any case, the Dow Jones Zeebrugge
Index Gas (ZIG) reflects a price that is again moving closer to
the level recorded in 2008, before the current crisis struck.
It may therefore be said that the extremely low short-term
price seen in 2009 is coming to an end.
E. Integration with intra-European regions
and neighbouring member states
The third European legislative energy package makes regional cooperation between regulators compulsory. The question of how this cooperation was to be organised and/or
whether the existing platforms or initiatives were able to
participate in this was the subject of discussions in 2010.
First of all, the gas regional initiative for the north-west region (GRI-NW) issued an initial proposal during the stakeholders group meeting on 26 November 2010 in Brussels.
The bottom-up approach so much appreciated in the past
through various projects remains an important pillar, but
in future will need to be accompanied by monitoring and
the top-down implementation of network codes which will
result from the third legislative package. The cooperation
cautiously introduced between the member states and the
European Commission continues to be supported.
of supply. In addition, pilot projects are only possible on the
basis of network codes and key guiding threads.
The discussions on this Commission communication, which
began in July 2010 during the fourth “Regional Initiatives”116
conference, are to continue in 2011.
The topics discussed at this conference also included the
objective of a fully coupled market for electricity (by 2015)
and natural gas.
These discussions did not, however, prevent regional initiatives from recording results in their current form. The North/
North-West of Europe gas region (Belgium, The Netherlands, France, Germany, Great Britain, Ireland, Northern Ireland, Denmark and Sweden) focused its activities around
three areas in 2010, i.e. investments, the secondary market
and capacity (short-term primary market).
In addition to the regional cooperation initiated by the regulators, the CREG participated in the gas platform that brings
together the authorities, the regulators and the TSOs of five
countries (The Netherlands, Luxembourg, France, Germany
and Belgium). Again in the wake of the Ukraine-Russia crisis,
the gas platform focused its work on the issue of the security
of supply. The processes, models and interventions at European level were applied specifically to the five countries with
a view to gaining a better understanding of the impact for
each of the countries concerned. The last two meetings discussed the impact of the third legislative package on the rules
in force in each of these five countries.
The strategic discussions do not prevent the markets
from functioning or continuing to develop. The hubs and
exchanges in the region around Belgium, including the
Zeebrugge hub in Belgium, posted similar sustained growth
in 2010, as well as rising liquidity. The only noteworthy fact
is the doubling of the churn factor at the Zeebrugge hub.
This is an indication of the number of times gas is exchanged before being physically taken elsewhere. Since October 2010, which was the start of the new gas year, this has
risen from 5 to 10. Analysis shows that this doubling is not
due to an increase in the volume exchanged (this remains
constant), but rather to the fact that the physical quantity
going through the hub has fallen by half.
On 7 December 2010, the European Commission published
a communication115 presenting other emphases or even an
adaptation of a number of regional geographic zones (but
which leaves the GRI NW region unchanged). A new Steering Committee, bringing together representatives of the
Commission, the member states and the regulators, could
play a central role here. Subject matters to be dealt with,
which would be imposed on a top-down basis, relate to investments in infrastructure, regional balancing and security
115 COM(2010)721 final: Communication from the Commission to the European Parliament and Council on the future role of regional initiatives.
116 http://www.energy-regulators.eu/portal/page/portal/EER_HOME/EERINITIATIVES/Regional.
61
Figure 25: Natural gas supplies by type and length of contract
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
2000
2001
2002
2003
2004
short-term supply (spot) and contracts of less than one year
contracts of less than one year concluded with other suppliers
contracts concluded with producers that end in five years
contracts concluded with producers that last more than five years
F. Integration between gas producers/importers
and suppliers – long-term gas supply contracts
For the 2010 breakdown, readers are referred to paragraph
4.2.1.A of this report and Figure 25 above.
G. Access to natural gas storage facilities
A systematic lack of gas storage capacity may be observed in Belgium. The Gas Act stipulates that access to the
storage facilities is reserved as a priority for companies
that supply end customers connected to the distribution
networks. There is no freely available storage capacity.
In 2007, Fluxys started an extension project intended to
increase the underground storage capacity in Loenhout.
In practical terms, the useful storage capacity will be gradually increased from 600 to 700 million cubic metres (i.e.
by 15%), over a period of four years (2008 – 2001). The
extension work is on schedule, which means that storage
users will benefit from a useful volume of around 700 million cubic metres by the 2011-2012 storage season. Fluxys is
also seeking to increase flexibility in the use of storage: the
issue capacity of the Loenhout facility rose from 500,000
to 600,000 cubic metres an hour on 1 November 2010 and
the injection capacity rose from 250,000 to 325,000 cubic
metres an hour on 1 July 2010.
62
2005
2006
2007
2008
2009
2010
Source: CREG
In 2010, the transmission company continued to offer flexibility services for storage in the short term by using the
virtual storage concept. At the request of the CREG, the
formula used will contribute towards simplifying access to
the network for newcomers and small players.
Access to the storage facilities is set by the Gas Act on
the basis of the market share on the distribution market.
No congestion management principle or CMP is therefore
necessary.
In principle, the capacity can be traded on the secondary
market, but there is no supply on the secondary market
owing to the lack of available storage capacity.
The capacity is offered in SBUs (Standard Bundled Units).
Storages users are provided with information about the storage capacity, the injection and emission capacity and parameters relating to the availability of the storage facility. This
information is available on a daily basis.
H. Developments in terms of market concentration
In 2010, a total of fourteen supply companies were operating on the Belgian market. Total natural gas consumption
rose to 241.7 TWh, an increase of 10.6% compared with
consumption in 2009 (194.2 TWh).
The merger between GDF and SUEZ and the fulfilment
of the conditions imposed by the European Commission
following approval of the merger in 2008 had a profound
impact on the way the market developed in 2010 and in particular on the market shares of Distrigas and the GDF SUEZ
group on the gas transmission market. With a market share
of 52.2%, Distrigas remained the dominant player in 2010.
The table below shows two major groups, ENI Distrigas and
GDF SUEZ. The concentration is measured using the HHI
index117.
Figure 26: IGH-Electrabel household customer – 2010.
19,00%
Energy
Transmission
Distribution (not including
public offtake)
0,96%
Public offtake
Energy tax and VAT
25,70%
51,98%
Source: CREG
2,37%
Prices charged to household end users rose compared with
2009.
Table 15: M
arket shares on the transmission system
from 2007 to 2010
2007
%
2008
%
2009
%
2010
%
ENI Distrigas
78.2
72.4
70.0
52.1
GdF Suez
15.2
13.0
12.4
27.2
Wingas
6.0
6.6
6.0
4.9
EDF SPE
0.1
6.5
7.8
9.9
Other (< 2%)
0.5
1.6
3.9
5.7
6,400
5,500
5,200
HHI
establish the contribution made by the various components
to the way in which prices have developed. The components
and the relative share in the price charged to the end user
are shown in the graph below.
3,600
Source: CREG
I. Mergers and acquisitions
The acquisition by Publigaz of all Electrabel shares in Fluxys,
as provided for in the agreement concluded on 23 March
2010 between Publigaz and Electrabel and as developed
in the buy-sell agreement of 30 April 2010, took place on
5 May 2010. Consequently, Publigaz owns a total stake of
89.97% in Fluxys.
See also paragraph 4.1.3. of this report.
J. Price trends
Household customers
Like electricity, following the sharp increase in 2008 and
the downturn in 2009 (caused mainly by the economic
crisis and its impact on the commodities markets, further
strengthened by the surplus supply of natural gas on international markets after the discovery of shale gas and the
over-capacity of LNG), natural gas increased again in 2010,
without however reaching the 2008 level. In 2009-2010, we
also observed a decoupling of natural gas prices from the
price of oil. This decoupling proved advantageous during the
period 2009-2010 for suppliers who buy their natural gas on
the spot market, such as Lampiris.
The trend in suppliers’ prices, which varies from one supplier to another, lies behind the increase seen in 2009-2010.
This increase is, however, partly offset by the fall in transmission tariffs and the reduction in levies. The transmission
tariff is 15% lower than in 2009, which corresponds to a
fall of € 0.24/MWh. The ‘federal contribution’ and ‘protected
customer surcharge’ levies have fallen by € 0.06/MWh.
At the request of the Minister for Energy, the Management Board analysed the range of fixed tariffs from suppliers active on the Belgian electricity and gas market118. The
conclusions of this study are set out in paragraph 3.2.2. of
this report, under the heading “Study on the overview of
fixed-price contracts on the household electricity and gas
market.”
The study (F)101021-CDC-1004 analyses the trend in the
price of natural gas for end customers since 2004 so as to
118 Study (F)100129-CDC-943.
63
Figure 27: Trend in total natural gas price – household customers (T2)
80
70
60
€/MWh
50
40
30
20
10
0
Jan 07
Apr 07
Jun 07
Oct 07
Electrabel
Luminus
Lampiris
Jan 08
Apr 08
Jun 08
Oct 08
Jan 09
Apr 09
Jun 09
Oct 09
Jan 10
Apr 10
Jun 10
Nuon
Essent
Source: CREG
Figure 28: Trend in energy price per supplier – household customers (T2)
50
45
40
€/MWh
35
30
25
20
15
10
Jan 07
Apr 07
Electrabel
Luminus
Lampiris
Jun 07
Oct 07
Jan 08
Apr 08
Jun 08
Oct 08
Jan 09
Apr 09
Jun 09
Oct 09
Jan 10
Apr 10
Jun 10
Nuon
Essent
Source: CREG
64
Business customers
Moreover, the Management Board also examined the relationship between costs and the prices of importers, retailers and suppliers on the Belgian natural gas market during
the 2007-2009 time period119. This study is in line with the
studies on the price rises for natural gas and electricity
announced by Electrabel and the relationship between the
costs and the prices of importers and retailers on the Belgian household and business market for natural gas over the
2004-2009 time frame120. Nevertheless, it aims to be more
exhaustive in that the prices and costs of all the players
on the liberalised market have been analysed with regard
to imports, retail and supplies to household and industrial
customers.
Business customers are seen to experience the same development as household customers because the suppliers’
price is based on the same parameters.
4.2.2. M
easures aimed at preventing any abuse
of a dominant position
The decline in the GDF SUEZ stake in the shareholding body
of Fluxys and Fluxys LNG was crucial in the fight to avoid
abuse of a dominant position in Belgium (cf. paragraph 4.1.3
of this report).
The study shows that the retail margins and supply margins
increased over the 2007-2009 time period compared with
the period prior to liberalisation. It indicates that the only
really competitive market segment seems to be the segment of supply to industrial customers, which is showing
a gradual decline in market share of the historical operator
in favour of various suppliers. As regards household customers, the study deplores the inertia of most consumers on
the one hand, but also the lack of dynamism among most
suppliers on the other. With one exception, these suppliers
still used the indexation formulas from the captive market
and based on oil contributions whereas indexation on the
basis of the gas contributions has been more advantageous
for customers since the start of 2009.
Liquidity on the wholesale market
Given that the Belgian market is one of the markets most
connected with its neighbouring countries in Europe, liquidity in Belgium is closely linked to the development of the
markets in these countries. The efforts made by the CREG
in terms of promoting liquidity are therefore mainly undertaken at a European regional level.
Figure 29: Energy price trend per supplier – business customer (T4)
50
45
40
€/MWh
35
30
25
20
15
10
Jan 07
Apr 07
Electrabel
Luminus
Lampiris
Jun 07
Oct 07
Jan 08
Apr 08
Jun 08
Oct 08
Jan 09
Apr 09
Jun 09
Oct 09
Jan 10
Apr 10
Jun 10
Nuon
Essent
Source: CREG
119 Study (F)101014-CDC-992.
120 Studies (F)070727-CDC-704 of 27 July 2007 and (F)091001-CDC-921 of 1 October 2009.
65
Given that the Belgian market is one of the markets most
connected with its neighbouring countries in Europe, liquidity in Belgium is closely linked to the development of the
markets in these countries. The efforts made by the CREG
in terms of promoting liquidity are therefore mainly undertaken at a European regional level.
The infrastructure improvements to be brought into service
over the next few years will underpin regional interaction.
In addition, in 2010 the Management Board finalised the
ERGEG study on better practices for gas hub monitoring
started in 2009121. Among other things, the study names the
Zeebrugge hub as the only non-regulated hub in Europe. In
this respect, Belgium therefore has a considerable amount
of ground to make up.
Further to the recommendations made in this ERGEG study,
the CREG:
• will work on the installation of a single hub for the
Belgian balancing zone. The fact that this situation has
arisen is due not only to the de facto monopolistic
situation of the hub, but also to the fact that the fragmentation of liquidity on the market must be avoided
to promote competition;
• will continue to argue for the regulator to have an overall
view of the hub, the main purpose being to be able to
guarantee non-discrimination in terms of access conditions. It is important to take account of the fact that this
overall view does not disrupt commercial activities;
• will endeavour to draw up new rules concerning the
rights and responsibilities of each party so as to guarantee that the hub functions efficiently and constantly
and that information is circulated as best as possible;
• will continue to stress the need to adapt the range of
services on offer to the needs of the market to a better
standard and and to adapt to the best practices that can
be found in Europe;
• will argue in favour of guidelines in the field of transparency and the provision of information concerning the
gas hub. The data should be accessible in the same
way to all the members of hubs, whether or not they
undertake any physical activities.
The dependence on the monopolistic position of GasTerra for
L-gas supplies is being curbed, which represents major progress in terms of competition.
In addition to the initial problem of supply, the analysis conducted in this document revealed a problem of cost control with
regard to the extension of conversion facilities and additional
flexibility resources. The fewer production resources there
are in the Groningen gas field, the more conversion and additional flexibility will be required in The Netherlands. It is difficult to assess the level of the conversion cost which remains
acceptable owing to the fact that this cost is an intrinsic part
of the transmission tariff in The Netherlands (less than 10%
at the moment). In future, strict follow-up and coordination
will be required.
Finally, the CREG goes on to add that the availability of and
access to cross-border capacity at the Hilvarenbeek/Poppel
interconnection point are giving cause for concern. Long-term
strategic choices will have to be made to ensure adequate firm
capacity. In The Netherlands, it will not be possible to make
adequate reservations in the long term to be able to maintain
the required level of exit capacity for the downstream markets.
The results provide a path towards a short-term solution.
With this study, the Management Board undertook to demonstrate that owing to its monolithic structure, the L-gas market
between The Netherlands, Belgium and France offers the most
obvious opportunity to put this cooperation into practice. It will
be difficult to continue to defend the inadequate processes
resulting in a unilateral reduction in available capacity without
taking account of the cross-border effects from a legal perspective once the underlying market requirements have been
clearly demonstrated and no alternatives are available, even if
these come under a different member state.
With regard to the situation within Belgium, in its study
(F)100114-CDC936 on the development of a competitive regional market for low-calorific natural gas, the CREG published
a new interim analysis of the priority questions linked to the
Belgian L-gas market. This analysis shows that the reforms
undertaken in The Netherlands seem to provide a response
to the issue of the availability of L-gas, both at macroeconomic level (security of supply in Belgium) and as regards ease
of availability with regard to newcomers and smaller players.
121 Monitoring Report 2010 on the regulatory oversight of natural gas hubs (http://www.energy-regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_ERGEG_PAPERS/Gas/2010/
E10-GMM-11-03%20Gas%20Hub%20Monitoring%20Report%202010_final.pdf).
66
5. Security of supply
67
5.1. Electricity
Table 17: Breakdown of the installed capacity per type of power
station connected to Elia’s grid, per type of power
5.1.1. Demand
station, as at 31 December 2010
The demand of electrical power, that is net consumption
plus pumping power and grid losses, amounted to 90.1 TWh
in 2007, 90.2 TWh in 2008, 85.9 TWh in 2009 and 90.2 TWh
in 2010, i.e. an increase of 4.9% between 2009 and 2010.
Peak demand remained almost unchanged between 2009
and 2010.
The table below provides an overview of the power demand
and the peak capacity demand on the grids of the TSO and
the DSOs during the period 2007-2010.
Table 16: P
ower demand and peak capacity demand in Belgium
during the period 2007-2010
2007
2008
Installed capacity
Power station type
MW
%
Nuclear
5,926
37.5
CCGT and gas turbines
4,300
24.6
Conventional power stations
including multi-fuel
2,355
2.6
Cogeneration
795
14.9
Incinerators
187
5.0
88
1.2
236
0.6
95
1.5
1,388
8.8
Onshore wind turbines
118
0.7
Offshore wind turbines
196
1.2
Biomass
117
0.7
15,802
100.0
Diesel engines
Turbojets
Hydro excluding pumped storage
Pumped storage
2009
2010
Power demand122
(GWh)
90,109 90,202 85,946 90,200
Peak capacity
demand (MW) on
the grids of the TSO
and the DSOs
14,040 13,524
14,139 14,200
Source: Synergrid – Electricity flows in Belgium (2010: provisional data)
5.1.2. Generation
Installed capacity and generated power
The composition of the Belgian generation park connected
to Elia’s grid underwent a number of changes in 2010: 545
MW of generation capacity were decommissioned and 704
MW of additional generation capacity were brought into service. In addition to a series of new cogeneration units as
well as the launch of the Knippegroen power station, capacity was increased at two nuclear units in Doel. In addition,
Belwind brought into service 55 offshore wind turbines in
the second half of 2010, each of which provides a capacity
of 3 MW, bringing the total installed offshore capacity to
195.9 MW.
Total
Source: Elia
As regards the volumes of electricity generated, net electricity generation amounted to 85,800 GWh in 2010, compared with 84,724 GWh in 2009. The breakdown by type
of primary energy of the electrical power generated from
installations connected to Elia’s grid (including an estimate
of auto-generated power used locally) is given in the table
below.
Table 18: Breakdown of power generated per type
of primary energy
Power generated
Primary energy
MWh
%
45,723,502
53.3
25,816,355
30.1
5,350,522
6.2
65,180
0.1
Other auto-generated power
autoconsumed 1
5,073,887
5.9
Hydro and pumped storage2
1,635,125
1.9
Nuclear
2
Natural gas
2
Coal2
Fuel
2
Other
2
Total1
1
2,135,430
2.5
85,800,000
100.0
Source: Synergrid, provisional data
2
Source: Elia, provisional data
122 Including estimated auto-generation consumed directly by charges connected to Elia’s grid, pumping and losses. As estimated auto-generation consumed directly by charges connected to the
distribution networks is not available for 2010. For each year, the table provides the amount of power demanded excluding this non-injected auto-generation.
68
Investment projects in the centralised generation park
As at 31 December 2010, the investment projects and in
generation units were as follows:
• Planned projects (for which a permit or domain concession application is still under process): 2,502 MW (onshore only)
• Project authorised, but for which construction has not
yet begun: 4,567 MW, including 1,112 MW in offshore
wind farms;
• Projects under construction: 1,406 MW, including 460
MW in offshore wind farms.
These projects are also mentioned in paragraph 3.2.10C of
this report.
Legal powers of authority and legislation development
The CREG continues to play a significant role in the area of
the security of supply.
However, the CREG is not the only party to be involved in
this issue, given the Belgian institutional context on the one
hand and the distribution of powers of authority between
the regulator and the energy administration on the other
hand. While the regions have competence to settle “the
regional aspects of energy”, the federal authority remains
qualified to address “matters whose technical and economic indivisibility requires uniform implementation at national level” in the listed cases, i.e. the national plan for the
equipment of the electricity sector, the nuclear fuel cycle,
major storage infrastructures, the transmission and production of energy and the tariffs. In addition, the federal authority can settle everything that comes under the residual
powers, which means that when a matter cannot be linked
to one of the powers attributed to the regions, this matter
comes under the federal scope of authority. And so in principle new energy sources fall in the regional scope of authority. However, the federal authority remains qualified in the
North Sea and for the wind farms constructed in this zone
in particular, owing to the limitation of the territorial powers
of the regions to the territory of the region. The powers of
the federal authority are assumed either at the level of the
federal administration, which is the Directorate General for
Energy, or at the level of the regulator, the CREG.
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, which
is responsible amongst other things for examining applications (see paragraph 3.2.1. above). Irrespective of the type
of generation unit, the criteria for granting the permits basically stem from technical and financial considerations. From
a technical perspective, it consists in checking whether
the project for which a permit is requested will contribute
towards fulfilling public service obligations and compliance
with the adopted guidelines concerning the choice of primary sources and the technology to promote. The project
will also need to comply with a series of technical requirements and be environmentally friendly. The applicant will
have to provide proof of the required technical capabilities
with a view to the construction and operation of the generation unit, but also its dismantling. The applicant will also
have to have sufficient economic and financial resources to
successfully complete its project. All these criteria for the
permit to be awarded are intended to enable the Minister for Energy to satisfy himself that the project is viable.
Moreover, to date no prior permit or notification procedure
is in place for decommissioning old generating units. However, there are many such units, and this is hampering the
renewal of the generation park.
Domain concessions with a view to the construction
operation of power generation facilities using water,
rents or wind in marine environments (wind farms)
granted by the Minister for Energy after obtaining the
nion of the CREG.
and
curare
opi-
As regards the long-term supply perspectives, the CREG is
consulted in the context of the study on the outlook for electricity supplies, the so-called ‘prospective study’.
The CREG also has the power to advise on the draft plan
to develop the transmission system put forward by Elia.
This development plan covers a period of ten years and is
revised every four years. If the CREG finds that the investments planned here do not allow the TSO to meet the capacity requirements adequately and efficiently, the Minister
for Energy can require the latter to adapt the plan.
The CREG also has the power to approve the method used
to assess the primary, secondary and tertiary reserve capacity, which contributes towards ensuring the security, reliability and efficiency of the grid in the control area. Similarly,
it is entrusted with the task of approving the market operating rules intended to offset 15-minute imbalances.
Finally, the Electricity Act provides for several support measures, with a focus on the promotion of renewable energies. For instance, the King has put in place a mechanism
of green certificates for green energy generated by wind
farms in the North Sea. Elia has to purchase these green
certificates at a minimum price. The same obligations
apply to Elia for green certificates issued by the regional
authorities, although these cannot be exchanged for those
issued at federal level. In addition, the act stipulates that
Elia is to finance one-third of the cost of the submarine
cable intended for the wind farms in the North Sea, with
a maximum amount of € 25 million for a project involving
216 MW or more. This funding of € 25 million is reduced
proportionally when the project involves less than 216 MW.
The Act also provides for a support mechanism in favour of
69
holders of domain concessions, whose production gaps are
greater given the uncertainties inherent to wind as a source
of energy. Depending on the direction of the gap, Elia has
to buy from or sell to these holders the proportion of energy
corresponding to a percentage rate of the production gap.
Finally, support measures are provided for in the event of
the withdrawal of the domain concession for reasons other
than negligence on the part of the concession holder.
5.1.3. Transmission grid infrastructures
Investments
a) Development plan
The TSO has to draw up a new plan for the development
of the electricity transmission grid in collaboration with the
Directorate General for Energy and the Federal Planning Bureau. The draft development plan has to be submitted to the
CREG for an opinion.
This plan covers a ten-year period and has to be updated
every four years.
It contains a detailed estimate of the transmission capacity
needs. In addition, the development plan defines the investment programme to be implemented by the TSO and takes
into account the need for adequate reserve capacity and projects of common interest defined by the institutions of the
European Union in the field of trans-European grids.
In this context, the Management Board issued an opinion
on Elia’s 2010-2012 draft development plan123. In its opinion,
the Board draws attention to a number of shortcomings in
the plan, including the fact that it fails to cover replacement
investments and makes virtually no mention of the estimated investment cost or alternatives. Also it fails to contain a
concrete and quantified roadmap to create an offshore grid,
nor does it contain sufficient investments to jointly connect
all the known projects for new generation facilities at the
same time.
b) Main investments in the transmission grid
In 2010, RTE, the French TSO, and Elia installed the second
225 kV aerial three-phase circuit on an existing 15 km electrical line linking Moulaine (France) and Aubange (Belgium).
Thanks to the use of a new type of electrical conductor,
the capacity transmitted per three-phase circuit can be
increased by more than 20%. This new type of conductor
123 Opinion (A)101014-CDC-994.
70
was not only used for the new set of cables, but also for the
existing one. According to Elia, this investment increases
the exchange capacity between France and Belgium by 10%
to 15%. In addition, a new underground 150 kV cable has
been laid between the Blauwe Toren and Bruges substations as part of the measures to increase capacity between
the coast and inland regions of the country.
The main development of the transmission grid for the future
is the Stevin project planned by Elia. This consists of extending the 380 kV grid between Zomergem and Zeebrugge.
This grid reinforcement enables Elia to meet three needs:
• it carries the power generated by the offshore wind
farms to the interior of the country;
• it creates the conditions for a new interconnection of
the Belgian grid by a submarine link with the United
Kingdom. This project is currently being studied. In
the longer term, Elia is also considering expanding its
interconnections via the North Sea to gain access to
the sustainable (renewable) energy mix coming mainly
from northern Europe;
• thanks to this extension of the 380 kV grid towards
the coast, it improves the security of the electricity
supply in western Flanders and enables the continued
economic development of the port of Zeebrugge and
the surrounding area, which constitutes a strategically
important growth centre.
The timing of this project depends largely on the length of
the various permit procedures needed for the construction of
the project and the way they progress. These are scheduled
to be completed by the end of 2012. The actual work could
then start in early 2013 to be completed by the end of 2014.
Grid security
A substantial proportion of the physical energy flows comes
from cross-border transits of electricity crossing the Belgian grid. According to Elia, physical transits accounted for
approximately 8.0 TWh in 2010, an increase of 1.8 TWh compared with 2009. As in previous years, the trend in non-nominated flows varies with the seasons. In 2010, these flows
tended to run from North to South between January and
May and between October and December. During the summer period (June-September) the trend shifted from South
to North. At their peak, these flows reached approximately
2,442 MW from North to South and approximately 2,059
MW from South to North.
Generally speaking, non-identified flows can now be limited
by the phase-shifting transformers with which all the interconnections on the northern border have been equipped
since the end of 2008. The peaks observed are usually due to
the non-availability of a phase-shifting transformers or restrictions in the surrounding grids. For example, on 6 June 2010,
the Zandvliet phase-shifting transformer was out of service
as part of the “BRABO” project (development of the grid in
the port of Antwerp). On that day, the non-nominated flows
went from South to North, up to over 2,000 MW.
These situations illustrate the fact that preventive solutions
dealing with non-identified flows are increasingly complex
and that the robustness of the grid is weakened in these
cases.
Certain possible incidents lead to potential problems
which have not been encountered hitherto. The situations
are constantly from one hour to the next and depend on a
series of parameters that vary just as much: exchange programmes, non-identified flows linked among other things to
wind-generated power, the generation park, etc.
To cope with these situations, coordination with the neighbouring TSOs again appears to be essential. Only solutions
that have been jointly examined and implemented make it
possible to keep the grid security under control. Similarly,
the modification of transmission capacities will have a real
impact only if coordinated at international level (a BelgiumNetherlands modification has little impact if there is no
Netherlands-Germany modification).
Coreso, the first regional technical coordination centre common to several TSOs was created on 19 December 2008
by the French and Belgian TSOs, RTE and Elia. Its activities,
which got underway in Brussels in early 2009, will contribute to reinforcing the electricity security in Europe. The
National Grid (UK) became a member of Coreso in mid-2009
and Terna (Italy) and 50 Hertz (northern and eastern Germany) became members in late 2010. The territory monitored
by Coreso has therefore expanded considerably.
5.2. Gas
5.2.1. Demand
In 2010, total natural gas consumption amounted to
215.3 TWh, i.e. a considerable rise (+ 10.9%) compared
with consumption in 2009 (194.2 TWh). This increase is due
entirely to a strong recovery in industrial demand for natural
gas (+ 19.7%), which almost reached the level of consumption in 2008, and to a considerable increase in consumption
on DSOs (+ 15.5%). The explanation for the peak in natural gas consumption among small consumers is due to the
very harsh winter which was felt both at the beginning and
at the end of 2010, resulting in a 22% increase in estimated
heating requirements.
Table 19: Breakdown per sector of the Belgian demand for natural gas between 2001 and 2010 (in TWh)
Sectors
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2010/2009
Distribution
81.1
78.3
83.1
88.3
87.2
88.3
82.6
88.5
87.6
101.2
+ 15.5%
Industry
(direct customers)
52.2
54.7
50.7
49.3
50.2
50.2
50.0
47.8
39.2
46.9
+ 19.7%
Electricity generation
(centralised park)
37.5
40.9
51.1
49.7
52.5
51.9
56.7
54.6
67.3
67.1
- 0.3%
170.8
173.9
184.9
187.3
189.9
190.4
189.3
190.9
194.2
215.3
+ 10.9%
Total
Source: CREG
71
Figure 30: D
evelopment of the natural gas consumption per sector during the 1990-2010 period (1990 = 100), corrected for climate
changes
460
440
420
400
380
360
340
320
300
280
260
240
220
200
180
160
140
120
100
80
199019911992199319941995199619971998199920002001200220032004200520062007200820092010
Household and
100 99 105109116 116 113122129134143137146145155158162169164 166156
equivalent
Industry
100 92 100103 111124132131138149155145152141137140139139132 109130
Electricity
generation 100 118 122127133161171180240295271255278348338357353386372 458457
total
100 99 105109116125129134148162165156166171172177178186179 182186
Source: CREG
In 2010, it appears that the share of H-gas expressed as
a percentage has slightly fallen to 73.6% (73.8% in 2009),
the balance (26.4%) being covered by L-gas. This is due to
the development of the market segments, as illustrated in
the graph below: a sharp rise in the distribution networks
consumption (+ 15.5%) combined with the quasi-stable
consumption of gas used for electricity generation (-0.3%).
Figure 31: Breakdown per sector of the Belgian demand for H-gas and L-gas in 2009 and 2010.
120
100
Offtake (TWh)
80
60
40
20
0
Total H
Public distribution
2009
72
2010
L
Total H
Industrial customers
L
Total
H
L
Electricity generation
Source: CREG
Forecasts for natural gas demand in Belgium are shown in
Figure 32. These are obtained by establishing the sum of
the final demand in the household sector, the tertiary sector, the industry and the demand for natural gas for the generation of electricity. As such, these figures relate to trends
that have been normalised for temperature.
Figure 32: Forecasts demand for natural gas in Belgium until 2020 (GWh, normalised t°, H+L)
300,000
250,000
GWh
200,000
150,000
100,000
50,000
0
2000
H+L
2001
2002
H
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
The forecasts are based on the “irrigation zones” for H-gas
and L-gas as they were in 2008, and without any intervention as regards the conversion of L-gas customers to H-gas.
According to the scenario planning, natural gas demand in
Belgium will rise to 183,516 GWh in 2020 for H-gas and
59,659 GWh for L-gas. In the meantime, the forecasts show
that demand in Belgium will reach 158,972 GWh for H-gas
and 54,208 GWh for L-gas in 2013.
2015
2016
2017
2018
2019
2020
Source: CREG
L
According to the scenario planning, natural gas demand in
Belgium will rise to 243.174 GWh in 2020. In the meantime,
the forecasts show that demand for natural gas in Belgium
will reach 213,180 GWh in 2013.
2014
5.2.2. Supply
In 2010, a total of fourteen supply companies were operating on the Belgian market. Total natural gas consumption
rose to 215.3 TWh, which represents an increase of 10.9%
compared with consumption in 2009 (194.2 TWh).
The GDF-SUEZ merger and the fulfilment of the conditions
imposed by the European Commission further to the approval of the merger in 2008 had a profound impact on the
development of the market in 2010 and in particular on the
market shares of Distrigas and the GDF SUEZ group on
the gas transmission market. With a 52.1% market share,
Distrigas remained the dominant player in 2010.
73
Figure 33: Market shares on the transmission grid in 2010
Vattenfall Energy
Trading Netherlands N.V.
1%
Statoil ASA
2%
RWE Supply & Trading Netherlands B.V.
1%
RWE Energy Belgium B.V.B.A.
1%
WINGAS GmbH & Co. KG
5%
SPE
9%
Distrigas S.A.
52%
Lampiris S.A.
1%
GDF Suez
18%
Eneco Energy Trade B.V.
0%
Électricité de France
1%
Specific European legislation for incident management is
now in force and will have to be taken into account in the
investment plans. This European Regulation No 994/2010124
includes a major modification in as much as specific standards are imposed both as regards the availability of natural
gas and as regards the infrastructure.
Reserve capacity
Electrabel S.A.
9%
E.On Ruhrgas AG
0%
E.On Energy Trading SE
0%
Source: CREG
5.2.3. Measures in emergency situations
n
shorter period of time owing to the minimum delays for new
nominations and renominations. This means that the TSO
should make provision for incident resources for a minimum
volume of 4,800 k.m³(n). In this respect, the TSO should
ideally take into account an additional linepack (gas in pipeline) in its investments plan.
As of 2010, the entry capacity will be sufficient in accordance with the “n-1” precautionary principle. In 2012, the
planned entry capacity will amount to 5,810 k.m³(n) whereas the total entry capacity for H-gas, including supplies
to L/H conversion facilities) will amount to 4,067 k.m³(n)/h.
The difference of 1,743 k.m³(n) /h is more than sufficient to
deal with a shutdown of the most important entry point, the
LNG terminal.
High-calorific natural gas market
Natural gas reserve
Under the TSO’s investments plan, part of the creation of
capacity of the rTr2/VTN2 pipeline (see paragraph 5.4.2. below) is taken over by the increase in the reserve linepack for
the management of incidents from 1,150 k.m³(n) to 1,750
k.m³(n).
The reserve linepack makes it possible to overcome the biggest fall in supply flows, for example a technical shutdown
of 2 to 2.5 hours in extreme peak periods. This is a minimum period in which it is presumed that all the flexibility
resources for the normal network balancing have already
been used which means they are no longer available to be
used for incident management. Outside peak periods, the
transition period increases and part of the normal flexibility
resources can be dedicated to incident management.
From an incident management perspective it should ideally
be made possible that an incident (starting from the worstcase scenario, that is the largest supply flow) is dealt with
for a minimum of six hours to give the market a minimum
amount of time to reorganise its own supply portfolios and
deliveries. It is difficult for the market to be reorganised in a
It is recommended that the application of the infrastructure standards imposed by European Regulation 994/2010
should be clearly identifiable in the investment plan.
n
Low-calorific natural gas market
Incident management on the natural L-gas market is problematic due to the fact that gas is supplied via a single route,
the limited buffer possibilities in pipelines, the limited possibilities for the conversion of H-gas to L-gas by the injection
of nitrogen, and the lack of L-gas storage facilities on the
Belgian territory.
A form of incident management is necessary however,
given the size and nature of the Belgian L-gas market. The
Brussels-Capital Region and the city of Antwerp are entirely
dependent on L-gas for instance. It is recommended that a
specific incident policy is developed for the L-gas market.
Once again, the terms and procedures governing the use
of L-gas underground storage capacity in France have to be
examined more closely in consultation with all the stakeholders involved.
The following table provides a general assessment of the
existing resources in case of an emergency situation.
124 European Parliament and Council Regulation 994/2010 of 20 October 2010 concerning measures to safeguard security of the natural gas supply and repealing Council Directive 2004/67/EC (Official Journalof the European Union of 12 November 2010).
74
Table 20: Existing tools in the event of an emergency situation
High-calorific natural gas market
Low-calorific natural gas market
Incident management Insufficient reserve capacity in accordance with
the “n-1” principle until the end of 2011. As of
2012, sufficient reserve capacity.
Reserve natural gas of the transmission grid operator insufficient to overcome a major incident for
six hours.
An alternative is to rely on assistance via transit /
Zeebrugge hub.
Need for an operational procedure and regulation
for incident management.
Problematic because there is one route and one
source. A technical incident on the import line
during peak time immediately results in a crisis
situation with the activation of a crisis plan: customer disconnection.
Need for operational procedure for incidents
management.
Examination of the use of the L-gas storage site in
France and imports from France.
Source: CREG
n
New European regulation
A new European regulation deals with the issue of the security of supply125. This regulation, which entered into force on
2 December 2010, imposes specific standards for the availability of natural gas and infrastructures. As regards L-gas, a
regional approach is needed for the proper application of the
regulation. Cooperation with The Netherlands and possibly
other countries consuming L-gas (France and Germany) will
be necessary for an appropriate management of incidents.
5.2.4. Investment
Storage capacity extension
As part of the gradual extension of the underground storage
capacity in Loenhout, the useful storage volume has been
increased from 650 million of cubic metres of natural gas in
2009 to 675 million cubic metres in 2010. The last provisional phase will be undertaken in 2011, increasing the useful
storage volume to 700 million cubic metres of natural gas.
Use of the storage capacity has been made more flexible by
increasing the emission capacity and the injection capacity.
Reinforcement of Northern Limbourg
In 2010, a major extension of the existing H-gas pipeline was
undertaken from the Dilsen entry point to Lommel, in a territory mainly supplied by Dutch L-gas. This H-gas pipeline runs
from Lommel to Tessenderlo via Ham. This connection will
supply the new CCGT electric power station at the Tessenderlo Chemie site. In addition, it will enable customers to
switch from L-gas to H-gas in the crossed region, first and
foremost for industrial customers along the Albert canal. To
continue to guarantee the security of supply, the pipeline
from the Dilsen entry point has been reinforced locally.
rTr2/VTN2
The laying of the rTr2/VTN2 pipeline in parallel to the existing bi-directional rTr1/VTN1 pipeline along a stretch of almost
170 km between Eynatten and Opwijk is the main achievement of 2010. This pipeline has been laid in response to the
market demand for over 10 billion cubic metres in additional
capacity for cross-border transactions between the Eynatten,
Zeebrugge and Zelzate interconnections. This gives a further
boost to access to the Zeebrugge hub and it will be possible
to supply the Belgian market more easily from the East. In
this respect, it has also been made possible since 1 October
2010 to physically export as well as to import natural gas via
the existing interconnection with The Netherlands at Zelzate.
This is a major achievement for the security of supply. Moreover, it is entirely in line with European Regulation N° 994/2010
which entered into force in December 2010 with a view to
establishing bi-directional interconnections by 2 December
2013. These achievements are fully in line with the plan aimed
at making Belgium the crossroads for natural gas in NorthWestern Europe.
Reinforcement of North/South axis
The North/South project is the result of a market consultation
coordinated by Fluxys and the French TSO, GRTgaz, held over
the 2007-2008 time frame under the supervision of the CREG
and and the French regulator (CRE) supervision. This Open
Season gauged market interest for new transmission capacities from border to border crossing Belgium towards France.
In this context, fourteen grid users concluded contracts of at
least ten years with Fluxys for new capacities from Zeebrugge,
Fouron-le-Comte or Eynatten, towards Blaregnies. The new
capacities cover a total of 10 billion cubic metres per year. The
additional compression capacity needed for this North/South
project is planned in Winksele and Berneau.
125 Regulation (EU) 994/2010, cf. note 124.
75
The additional compression in Berneau is planned by the
end of 2011 and will make it possible to carry additional natural gas flows from The Netherlands to Blaregnies.
5.2.5. Security of supply standards
The additional compression in Winksele on the rTr/VTN pipeline is planned by the end of 2012 and amongst other things
will, make it possible to move from three balancing zones to
a single national balancing point for the H-gas market. It may
be necessary to lay a new pipeline of approximately 125 km
between Winksele and Blaregnies, but possible rearrangements in the grid users’ border to border contracts portfolio
could make the decision on the new pipeline pointless by
the end of 2013.
In the past, on repeated occasions the CREG has expressed
its concerns over the limited supply of flexibility services for
storage in general and the lack of short-term storage services in particular. In order to fulfil its undertakings in this
respect, the TSO drew up a proposal for short-term services based on the virtual storage concept. The CREG asked
Fluxys to slightly adapt the proposed allocation rules so that
they more effectively meet the needs of grid users with
limited market share and those of potential new entrants
on the market. The new virtual storage concept, with the
exception of details of the allocation rules, was explained
to grid users (active and non-active) at a shippers meeting
held on 8 May 2009. The process of optimising the allocation rules continued under the working group consultation
between representatives from the CREG and Fluxys. The
initial entitlement to which virtual storage user can lay claim
is calculated on the basis of MTSR rights on the H-gas grid
that the user has subscribed. The formula used to calculate
the allocated entitlement takes into account the CREG’s
concern to facilitate access to the network for new and
small actors. The virtual storage service was included in the
2010-2011 indicative programme for storage services.
Open Season on transmission capacity from France to
Belgium
The first non-binding phase of a market consultation process that gauges the market’s interest in the transmission
capacity from France to Belgium was completed in 2010.
This consultation was launched further to the possible
construction of an LNG terminal in Dunkirk intended mainly
for international trade in Zeebrugge and the Belgian market.
This market consultation revealed sufficient interest for a
new pipeline to be laid from Dunkirk to Zeebrugge by means
of a new interconnection point in the Furnes region. However, the binding phase will not begin until the initiator, EDF,
decides whether to build a new LNG terminal in Dunkirk.
As at 31 December 2010, after numerous postponements,
a decision was still awaited. The new connection could result in an increased liquidity on the market by coupling the
Zeebrugge hub with the French PEG Nord spot market, not
to mention the synergies with the Zeebrugge LNG terminal.
The CREG conducted a study into this project (Study
(F)100211-CREG-945).
Open Season on transmission capacity to the Grand
Duchy of Luxembourg
In the second quarter of 2009, Fluxys launched an Open
Season for capacity between Belgium and the Grand Duchy
of Luxembourg. This Open Season closed at the end of
February 2010 and resulted in a sum of binding requests
amounting to a total of 172,000m³/h for the 2015-2025 time
frame. The capacities reserved as of 2015 are in line with
expectations and will give rise to limited investments.
A problem with the allocation of capacity intended for the
Grand Duchy of Luxembourg occurred for the 2010-2015
time period. Following the involvement of the CREG in this
case, discussions were held between the shippers concerned and the capacity allocation problem was resolved on a
negotiated basis between the shippers.
76
Virtual storage service
Dudzele peak shaving plant
The Dudzele peak shaving facility interrupted its activities
on 1 July 2010 owing to the unduly low interest from the
market, even in the medium term. The facility offered a peak
storage capacity of 59 million cubic metres of natural gas
and enabled the market to subscribe to an emission capacity of 360 m³(n)/h. There are obviously sufficient interesting
alternatives for the market to purchase flexibility or make
use of peak storage capacity abroad.
LNG terminal
In 2010, seven Q-Flex LNG tankers were unloaded in
Zeebrugge and truck loading contracts were concluded.
Moreover, Fluxys LNG loaded small LNG tankers. The shiploading and truck-loading services which were hitherto relatively underdeveloped are now starting to expand.
6. The CREG
77
6. The CREG
6.1. The assignments of the CREG
6.2. The Bodies of the CREG
In a preliminary ruling (ruling No 130/2010 of 18 November
2010), the Constitutional Court declared that it is compatible
with the Constitution to attribute to the CREG, which is not
managed directly by the executive power, prerogatives of
administrative authority such as monitoring the accounts of
companies in the electricity sector or issuing administrative
fines. More specifically, the Court decided that the lack of hierarchical control or administrative supervision over the CREG is
not contrary to the Constitution in that the CREG is an administrative authority which, while having a significant degree of
autonomy, is nevertheless subject to monitoring both by the
courts of law (Council of State/judicial courts) and by Parliament (its budget requires approval, its assignment and method
of operation are defined by law, its annual report is passed on
to the legislator and the competent minister has parliamentary
responsibility). The Court added that the fact that the CREG fulfils its assignments with a high level of autonomy results from
the requirements of European Union law, which has gradually
become more explicit in this area.
6.2.1. The General Council
Moreover, over the course of the year 2010, the chairman,
the directors and sixteen members of staff at the CREG were
appointed inspectors vested with the powers of authority of
officers of the judicial police.126. They have been entrusted with
the task of seeking out and establishing, across Belgium as
a whole, infringements of certain provisions of the Gas and
Electricity Acts, as well as the implementing decrees of these
Acts. The individuals in question took an oath before the Minister for Justice and will work under the supervision of the public
prosecutor attached to the Court of Appeal in Brussels.
Finally, with a view to the expiry of the period allowed for the
transposition of the third energy package on 3 March 2011, the
Management Board presented two studies on the legislative
amendments required to implement the reinforcement of
its powers. For a more in-depth discussion of these studies,
please refer to paragraph 2.7 of this report.
Isabelle Callens, Marc Leemans,
ChairmanVice-Chairman
In 2010, the chairmanship of the General Council was assumed
by Ms Isabelle Callens and the vice-chairmanship by Mr Marc
Leemans.
The General Council met eight times in 2010. An extraordinary
meeting was dedicated to the presentation of study 986 on
the amendments to be made to the Electricity Act in November (cf. paragraph 2.7 of this report).
The General Council unanimously approved the CREG draft
budget for 2011at its plenary meeting on 27 October 2010.
Thanks to the permanent presence of a representative of the
Minister for Energy, the work of the General Council was able
to focus on the most pressing aspects and periodic updates
were provided of the government’s concerns regarding gas
and electricity. The many current issues broached by members
made it possible to keep the Minister for Energy informed of
the concerns of the General Council.
The General Council was also informed of the positions adopted by the Management Board during hearings in the Chamber
of Representatives or at press conferences.
In 2010, the General Council put forward five opinions, all of
which are available to be consulted at the CREG website. Various studies undertaken by the Management Board as well as
questions asked by the Minister for Energy were prepared and
discussed in various working groups before being submitted to
the General Council.
1. Opinion 45 on Management Board study 945 concerning
the possible connection between the LNG terminal in Dunkerque and the Belgian natural gas transmission system
(‘functioning of the gas market’ working group).
In this opinion, the General Council upholds the conclusions
reached by the Management Board (cf. paragraph 5.2.4 of this
report) and also considers that:
126 Royal Decree of 25 June 2010 appointing members of the Management Board and members of staff of the Commission for Electricity and Gas Regulation as officers of the judicial police (Belgian
Official Journalof 23 July 2010).
78
6. The CREG
a) there is a need to keep an eye on healthy competition
between the Zeebrugge terminal and the future Dunkerque
terminal, particularly if the latter were to be entirely released
from regulated access rules;
b) the two terminals allow major synergies to be achieved by
increasing the flexibility of the grid and diversifying sources
of supply;
c) an international market study (Open Season), organised
jointly by Fluxys, GRTgaz (natural gas TSO in France), the
CRE (French energy regulator) and the CREG, offers the best
guarantees for an appropriate decision;
d) the new cross-border connection may not, under any circumstances, be a direct pipeline and must be connected to
the interconnected grid in France and in Belgium;
e) the connection gives rise to a physical bi-directional interconnection between the connected networks, provided that
this has socio-economic advantages for grid users; to do so
an initial, inevitable condition will be to work out a solution
with regard to odorisation and pressure requirements so
that natural gas can actually run from France to Belgium;
f) the connection must be covered by the regulated system,
both as regards access to the grid and tariffs;
g) the new connection must contribute towards efficient development in terms of costs and the operational management
of the transmission system; therefore, the impact of the
connection on existing activities (swapping or netting, backhaul) must be analysed.
In this opinion, the General Council also calls upon the French
and Belgian governments and regulators to follow these recommendations as closely as possible when approving and
authorising the connection between the French and Belgian
natural gas transmission system.
the possible impact of the electric car on the Belgium electricity system (ad hoc working group).
The ad hoc working group decided from the very beginning
not to analyse the Management Board study in detail (see
paragraph 3.2.2 of this report), but to make a summary of the
general vision on the issues.
In this opinion, the General Council asks the Management
Board to continue to reflect on the matter of the operation of
the Belgian market in light of the possible large-scale introduction of electric vehicles in Belgium and stresses the importance
of links between the use of electric vehicles, the networks and
the generation of electricity. Moreover, electric vehicles could
facilitate the integration of renewable energy sources.
The General Council’s opinion does not in any way overcome
the need for wider reflection in society on the issue of mobility
and intermodality in general and the importance of the electric
vehicle compared with other alternatives (hydrogen, etc.), so
as to make the most of the opportunities provided by electric
mobility. The General Council calls for the development of a
vision for Belgium and for Europe as a whole.
the initial estimate of the cost of the measures referred to
in Article 7 of the law of 29 April 1999 on the organisation of
the electricity market (‘renewable energies’ working group).
At its meeting on 20 January 2010, the General Council asked
the Management Board to conduct a study into the total cost of
the support provided for offshore wind farm producers in Belgian waters. In its study (F)100128-CDC-944, the Management
Board provided an initial response to this matter (cf. paragraph
3.2.1.C.c of this report).
The General Council recalled that it had already issued an opinion in May 2009 on the draft directive of the European Parliament and the Council on the promotion of the use of energy
from renewable sources. This Opinion 43 is available on the
CREG website.
In Opinion 47, the General Council makes numerous recommendations, relating in particular to: the selection of the optimal mix
of renewable energy sources to reach the targets, taking into
account all the social costs and benefits; the optimisation of
support mechanisms once the optimal mix of renewable energy
sources has been determined; the limitation of support measures to the additional cost compared with the market value of
energy produced using renewable sources; the cost of green
certificates, the cable and production deviation; and the revenue
for the payment of the support mechanism.
the Belgian short-term electricity market Belpex and the
use of capacity at the interconnections with France and
The Netherlands in 2009 (cf. paragraph 3.2.2 of this report)
(‘functioning of the electricity market’ working group).
In this opinion, the General Council:
a) notes that the market players have relatively positive experiences with the price mechanism on Belpex and with the
coupling of the trilateral market. The market coupling has certainly contributed towards greater convergence on the Dutch,
French and Belgian electricity markets. However, it can only
lead to full market integration provided that congestion on the
market can be limited so that it no longer (or virtually any longer) has an impact on the formation of market prices. The General Council is calling on the regulators, TSOs and exchanges
to seek out solutions together that could lead to full market
integration;
79
6. The CREG
b) notes that price peaks have occurred again and asks the regulators and, if necessary, the competition authorities in the
countries concerned to analyse these events in depth and if
necessary take steps to prevent such price peaks;
c) as regards market shares, the General Council notes that the
level of concentration on Belpex has decreased gradually over
the past few years. Nevertheless, concentration certainly remains high on the buyer’s side, and this worries the General
Council, which therefore requests rigorous monitoring by the
regulators;
d) notes that the market players also have a relatively positive
experience with the allocation mechanisms at the borders. In
order to achieve even better results, the General Council is inviting all the TSOs in the CWE region (Central West European
region), with regard to their own networks and cross-border
capacities, to:
- use the existing capacities even better; in addition
to the security of supply, system operators should
see better market functioning as one of their priority
objectives;
- find the most balanced distribution possible of long/
short-term capacities depending on the market
needs;
- invest quickly if necessary, in additional capacity to
reduce congestion, speed up price convergence and
hence facilitate market integration, as is the case
with the ‘Moulaine-Aubange’ line;
e) wishes to have a clearer view of the exact destination of
congestion rents by the various TSOs concerned;
f) also hopes that it will be possible to extend the coupling
between Belgium, The Netherlands and France to Germany
very quickly.
In this opinion, the General Council also invites the Management Board to continue to monitor the operation of the
Day-Ahead and the Intraday market in Belgium, the coupling
of these markets with neighbouring markets and the use of
capacity on the interconnections in conjunction with the other
transmission system operators and regulators concerned.
5. O
pinion 49 on Management Board study 874 concerning
natural gas supply needs, security of supply and infrastructure development 2009-2020 (‘functioning of the gas market’ working group).
In addition to the affordability of electricity and natural gas for
end consumers, the General Council remains very concerned
about the security of supply. While an opinion on the security
of supply for electricity was issued in 2009 (this opinion 42 is
available on the CREG website), no similar opinion had so far
been put forward with regard to natural gas supplies. This is
why the General Council wished to put forward the following
recommendations about the security of natural gas supply,
80
given a fortiori the importance of natural gas in the fuel mix of
the country, including for the generation of electricity.
a) The General Council feels that it is important to undertake
a long-term analysis of needs in terms of natural gas and
infrastructure for natural gas for the Belgian market on a regular basis. This is the best way to ensure that the necessary
resources are assigned in time so as to provide additional
volumes and infrastructure. The General Council therefore
calls upon the competent authorities to draw up the prospective study on the security of natural gas supply as quickly
as possible (the last indicative plan dates from 2004).
b) In the meantime, the General Council refers to the analysis
and recommendations made in CREG study 874 on natural
gas supply requirements, security of supply and infrastructure development 2009-2020 (this study is available on the
CREG website);
c) The General Council notes that to date, on the liberalised
market, no specific standards have been imposed in Belgian
legislation as regards security of natural gas supply. It therefore insists on the fact that the existing situation should be
compared with the requirements. It also stresses that future
European regulation on the security of natural gas supply will
impose binding standards in terms of natural gas infrastructure and supply. This regulation will be directly applicable in
the Belgian legal system;
d) Concerned, among other things, about finding a balance
between the infrastructure needed to ensure maximum
security of supply on the one hand and the competitiveness
of natural gas as an energy vector on the other, the General
Council asks to be involved in the interpretation of this regulation in Belgium;
e) As regards the high-calorific gas market, the General Council
does not question the investments planned by Fluxys, but
does make comments about the feasibility of the timing of
these projects. For instance, refraining from issuing permits
can cause delays and hence hamper access to the market
and threaten the security of supply. The General Council therefore stresses the need for a permits policy based on the
general interest and on the efficient monitoring of the rate at
which projects underway are implemented;
f) Low-calorific natural gas has played a major role in promoting
the use of natural gas in Belgium and still makes a substantial contribution to final consumers in Belgium in terms
of the flexibility of natural gas supplies. However, the General Council is concerned about the availability of the required level of long-term firm exit capacity at Hilvarenbeek, as
specified in Management Board study 936 (this study dating
from January 2010 is available on the CREG website). In this
context, it insists on a coordinated cross-border approach
between the countries concerned. In addition, the General
Council stresses that, despite the recent developments in
6. The CREG
the Dutch market model which have prompted a number
of new L-gas suppliers to enter the Belgian market, competition on the low-calorific natural gas market is still more
limited than that on the high-calorific natural gas market at
the moment.
The General Council is aware of the fact that the accessibility
and appeal of the Belgian market with a view to bringing in
flows of natural gas (both for import and for export) are key
elements in the security of supply, as well as the control over
demand for energy. It is therefore asking the system operator,
the authorities and the regulator to pay particular attention to
these issues and, by working out an adequate investment and
regulation policy, to continue the development of Belgium in its
role as a hub for natural gas in Europe.
Table 21: Members of the General Council as at 31 December 2010127
Federal government
Regional governments
Representative employees’ organisations sitting on the
National Labour Council
Representative employees’ organisations sitting on the
Council for Consumption
Organisations for the promotion and protection of the
general interests of small-scale users
Representative organisations of industry, and the banking
and insurance sector sitting on the Central Economic Council
Representative organisations of the crafts, small and
medium-sized trading companies and small-scale industry
sitting on the Central Economic Council
Major electricity consumers
Major natural gas consumers
Producers who are members of FEBEG (the Belgian
Federation of Electricity and Gas Enterprises)
Electricity producers renewable energy sources
Electricity producers cogeneration
Industries that generate electricity for their own needs
Distribution system operators
- INTERMIXT
- INTER-REGIES
TSO for electricity
TSO for natural gas
Holders of a supply permit for natural gas who are members
of FEBEG
Environmental associations
Holders of a supply permit for electricity who are members
of FEBEG
Market operator for the exchange of energy blocks proposed
by BELPEX
Chairman of the CREG Management Board
Actual members
DUJARDIN Davine
ANNANE Jihanne
CHAHID Ridouane
ROOBROUCK Nele
DE COSTER Nicolas
BIESEMAN Wilfried
AUTRIQUE Henri
JACQUET Annabelle
LEEMANS Marc
VERHUE Maureen
PANNEELS Anne
VERCAMST Jan
WILLEMS Tom
VAN DAELE Daniel
ADRIAENSSENS Claude
DOCHY Stéphane
CALLENS Isabelle
CHAPUT Isabelle
VAN der MAREN Olivier
ERNOTTE Pascal
VANDEN ABEELE Piet
Deputy members
DEWISPELAERE Sophie
NIKOLIC Diana
HOUTMAN Eric
BOEYKENS Marc
ONCLINX Philippe
TANGHE Martine
BOHET Maurice
DECROP Jehan
VAN MOL Christiaan
SKA Marie-Hélène
DE MOL Philippe
BAECKELANDT Filip
JONCKHEERE Caroline
STORME Sébastien
SPIESSENS Eric
RENSON Marie-Christine
DE BIE Nico
VANDERMARLIERE Frank
CALOZET Michel
AERTS Kristin
WERTH Francine
VAN GORP Michel
CLAES Peter
BRAET Luc
HERREMANS Jan
MAERTENS Paul
LAUMONT Noémie
STEVENS Tine
BÉCRET Jean-Pierre
EELENS Claire
de MUNCK Laurent
DE GROOF Christiaan
de VILLENFAGNE Aude
BODE Bart
MARENNE Yves
ZADORA Peter
HUGE Jacques
HUJOEL Luc
PEETERS Guy
DECLERCQ Christine
DEBATISSE Jennifer
VERSCHELDE Martin
DE BLOCK Gert
HOUGARDY Carine
FONCK Pascale
TUMMERS Paul
GILLIS Michaël
VAN NUNEN Carlos
VAN DYCK Sara
VANDE PUTTE Jan
HEYVAERT Griet
VAN BOXELAER Kathleen
VANDENBORRE Catherine
GERKENS Isabelle
DESCHUYTENEER Thierry
VAN GIJSEL Gert
DE BUCK Hilde
TURF Jan
VANDEBURIE Julien
GODTS Annemie
WYVERKENS Herman
LOOS Rob
POSSEMIERS François
Source: CREG
127 The list of members of the General Council was modified three times in 2010 by Ministerial Decree of 1 March (Belgian Official Journalof 19 March 2010), 30 March (Belgian official journal
of 7 April 2010) and 7 June (Belgian Official Journalof 22 June 2010).
81
6. The CREG
6.2.2. The Management Board
François Possemiers,
Chairman
Guido Camps,
Director
The Management Board is responsible for the operational
management of the CREG and undertakes everything that
is necessary or useful for the fulfilment of the assignments
entrusted to it by the Electricity Act and the Gas Act.
The chairman and the three directors who make up the Management Board deliberate as a college in accordance with
the usual rules on deliberating meetings.
The Management Board is chaired by Mr François
POSSEMIERS, who is also responsible for the management
82
Bernard Lacrosse,
Director
Dominique Woitrin,
Director
of the CREG. The three directors are Mr Guido CAMPS, who
is in charge of prices and accounts monitoring, Mr Bernard
LACROSSE, who heads the administrative directorate and
Mr Dominique WOITRIN, who is in charge of the technical
operation of the electricity and natural gas markets.
The members of the Management Board were appointed
by Royal Decree on 15 January 2007 for a six-year term of
office.
6. The CREG
Table 22: Directorates and staff of the CREG as at 31 December 2010
Chairmanship of the Management Board
POSSEMIERS François
DEVACHT Christiane
FIERS Jan
JACQUET Laurent
LOCQUET Koen
ROMBAUTS Josiane
Directorate for the technical operation of the markets
WOITRIN Dominique
GOOVAERTS Wendy
VAN KELECOM Inge
GHEURY Jacques
MARIEN Alain
MEES Emmeric
VAN ISTERDAEL Ivo
CLAUWAERT Geert
CUIJPERS Christian
DE WAELE Bart
FONTAINE Christian
PONCELET Yves
VAN HAUWERMEIREN Geert
FILS Jean-François
LUICKX Patrick
TIREZ Andreas
Directorate for price and accounts monitoring
CAMPS Guido
FELIX Kim
de RUETTE Patrick
LAERMANS Jan
WILBERZ Eric
ALLONSIUS Johan
CORNELIS Natalie
DEBRIGODE Patricia
DUBOIS Frédéric
JOOS Benedict
MAES Tom
BARZEELE Elke
COBUT Christine
DE MEYERE Francis
HERNOT Kurt
KUEN Nicolas
LIBERT Brice
PHILIPPE Quentin
PIECK An
BROODS David
MARTIN Sabine
Administrative directorate
LACROSSE Bernard
SELLESLAGH Arlette
General Council
DE LEEUW Han
HERREZEEL Marianne
General administration
DE PEUTER Caroline
ESSER Mercédès
HAESENDONCK Herman
VAN ZANDYCKE Benjamin
LOI Sofia
CEUPPENS Chris
DE DONCKER Nadine
VAN MAELE Nele
WYNS Evelyne
JUNCO Daniel
IT department
LAGNEAU Vincent
GORTS-HORLAY Pierre-Emmanuel
Finance
SCIMAR Paul
LECOCQ Nathalie
PINZAN Laurent
Studies, documentation and archives
BOUCQUEY Pascal
CHICHAH Chorok
DETAND Maria-Isabella
HEREMANS Barbara
PARTSCH Gwendoline
ROOBROUCK Myriam
SMEDTS Hilde
STEELANDT Laurence
ZEGERS Laetitia
GODDERIS Philip
HENGESCH Luc
Chairman of the Management Board
Assistant to the director
Secretary of the Management Board
Chief advisers
Director
Multi-purpose secretary
Chief advisers
Senior advisers
Advisers
Director
Chief advisers
Senior advisers
Advisers
Assistant advisers
Director
Advisers
Office Manager
Translators
Coordinator
Multi-purpose office staff
Logistics staff member
IT specialist
Assistant IT specialist
Head of Finance
Accountant
Administrative staff member
Senior advisers
Adviser
Archivist
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6. The CREG
6.3. General policy plan and comparative
report on the objectives and achievements
of the CREG
6.4. Cooperation with other bodies
As stipulated in the Electricity Act, the Management Board
prepared the general policy plan128 setting out the objectives
which the CREG aims to achieve in 2011. This plan accompanies the draft budget of the CREG and was handed to the
Minister for Energy on 29 October 2010 for submission to
the Council of Ministers.
As in previous years, in 2010 the CREG again drew up the
“National Report from Belgium to the European Commission”, working closely with the three regional regulators and
the Directorate General for Energy at the Federal Public Service Economy. This report enables the European Commission
to draw up its annual report on the progress made with the
creation of an internal electricity and natural gas market. The
report provides an overview of the Belgian electricity and gas
markets during 2009 and hence gives a view of the implementation of European legislation in Belgium. Major developments and striking facts in the period under review included
the adoption of the third European legislative package on the
internal market for electricity and natural gas, after two years
of debate at European level. The year 2009 was also marked
by several major acquisitions, including that of supplier Distrigas by Italian company Eni S.p.A. or that of the majority
of the shares in SPE (via Segebel) by EDF, as well as by the
consequences of previous mergers, such as that of SUEZ
and Gaz de France. A new Belgian Act was also approved
in 2009 which, amongst other things, forced the GDF SUEZ
group to reduce its stake in Fluxys to a maximum of 24.99
% by 31 December 2009 (cf. paragraph 4.1.3 of this report).
The structure of the general policy plan for 2011 has been
altered compared with that used for the general policy plan
for 2010. With the adoption of the third European energy
package and its transposition into Belgian law, scheduled for
3 March 2011 at the latest, new duties are entrusted to the
regulatory authorities. The new structure now distinguishes
between the CREG objectives to be attained as part of the
so-called ‘Business as usual’ scenario and the objectives
pursued further to the new duties entrusted to the national
regulator by the third package.
The first part of the general policy plan deals with the
context and the latest developments as regards the electricity and the gas markets, both in Belgium and in Europe.
In the second part the policy plan sets out in detail the 21
objectives that the CREG has set itself for 2011 and which
are included in concise form in the third part.
The Electricity Act also stipulates that every year a comparison should be made between the objectives as put forward
in the general policy plan and the extent to which they are
achieved. The Management Board drew up this comparative
report for the year 2009129 and handed it to the Minister for
Energy on 30 April 2010 for submission to the Council of
Ministers. In its general policy plan for 2009 the CREG had
identified 16 general objectives to be achieved. These objectives were divided into 97 actions that corresponded to the
individual assignments to be accomplished. In its comparative report for 2009 the CREG noted, however, that it had
undertaken a total of 113 actions in the context of the objectives initially set out. This increase of over 16 % in the number of actions undertaken is the result either of requests for
studies, opinions and proposals from the Minister for Energy
made over the course of 2009 or of initiatives taken by the
CREG to improve the operation of the electricity and the gas
markets. Of the 113 actions taken by the CREG in 2009, 58
actions were fully implemented, 8 yielded a better result than
hoped, 20 were largely completed by the CREG but could not
be finalised owing to external elements, 7 were largely completed, 6 were undertaken to a limited extent, 5 could not be
implemented and 9 no longer serve any purpose.
128 Plan (Z)101028-CDC-1003
129 Report (Z)100430-CDC-967.
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6.4.1. The CREG and the European Commission
In addition, the CREG cooperated on numerous other consultation processes and reports on behalf of the European
Commission via its membership of CEER and ERGEG (cf.
paragraph 6.4.6. below).
6.4.2. The CREG and ACER
Regulation (EC) 713/2009 of the European Parliament and of
the Council of 13 July 2009, published in the Official Journalon 14 August 2009, establishes an Agency for the Cooperation of Energy Regulators, known as ACER.
The assignment of ACER is to coordinate the work of the
national regulatory authorities at European level and its
duties include the following:
• participating in drafting European network codes;
• deciding on the terms and conditions for access to
and operational security applicable to cross-border
infrastructures;
• adopting individual decisions in specific areas;
• issuing opinions in a series of issues (on the draft statute of ENTSO-E and ENTSO-G (European Network
of TSOs for Electricity/Gas), on the ten-year network
development plans, etc);
• monitoring the internal electricity and natural gas markets in cooperation with the European Commission,
6. The CREG
the member states and the competent national authorities and informing the European Parliament, the
European Commission and the national authorities of
its conclusions;
• informing the European Commission when it notes
that a national regulatory authority is not complying
with certain provisions of the third energy package;
• s upervising regional cooperation between TSOs.
ACER was scheduled to be fully operational by 3 March
2011. Initially, CEER will continue to carry out the preparatory work of ACER until the latter is fully operational and has
its full staff complement. As soon as ACER is operational,
ERGEG (cf. paragraph 6.4.6 below) will cease to exist.
ACER will comprise an Administrative Board, a Board of
Regulators (within which the regulatory authorities of the
member states (including the CREG) are represented), a
Director, his staff and a Board of Appeal.
The Administrative Board met for the first time at the end
of March.
The first meeting of the Board of Regulators took place
on 4 and 5 May 2010 when the internal rules of procedure
established by CEER within the “Agency Project Team Task
Force” were approved and used as a basis for the election
of the chairman and vice-chairman of the Board of Regulators. There was a consensus among the national regulatory authorities to maintain an alignment, in the interests
of continuity, between the general assembly of CEER and
the ACER board of regulators, such that Lord John Mogg
(Ofggem) was elected chairman and Walter Boltz (e-control)
vice-chairman of the Board of Regulators.
Mr Alberto Pototschnig was appointed as ACER director on
6 May 2010 by the Administrative Board after obtaining the
opinion of the Board of Regulators. As soon as he took up
his post, the recruitment of staff got underway.
The procedure for appointing the members of the Board of
Appeal had not yet been completed by 31 December 2010.
The head office of ACER is in Ljublijana, Slovenia. However, its activities were provisionally undertaken in Brussels
in 2010, while awaiting the move to the official head office
in February 2011.
The Agency’s working programme for 2011 was prepared by
the national regulatory authorities (following prior approval
by the Board of Regulators) and approved by the Administrative Board on 23 September 2010130. The emphasis will be
placed on drafting framework guidelines, issuing opinions
on the draft statute, the list of members and draft rules of
procedure of the ENTSOs, issuing opinions on the conformity with the framework guidelines of the network codes
drawn up by the ENTSOs, adopting decisions on crossborder congestion and exemptions from third-party access
to the network. In addition, the Agency will undertake the
monitoring missions with which it has been entrusted as
quickly as possible.
In an initial phase, the Agency will set up three working
groups: an electricity working group, a gas working group
and a working group responsible for regional coordination.
6.4.3. The Madrid Forum
The European Gas Regulatory Forum, also known as the
Madrid Forum, serves as a platform for consultation on
the development of the internal natural gas market. Its participants include the European Commission, the member
states and the European regulators. The 17th and 18th meetings of the Forum were held on 14 and 15 January and 27
and 28 September131.
Since the publication in 2009 of the third European energy
package (cf. 2009 Annual Report, paragraph 1.2, p. 7), this
Forum has drawn up a statement of the situation of activities relating to the natural gas market with a view to facilitating implementation of the new European framework to be
transposed into national law by 3 March 2011.
The pilot projects for the development of the Framework
Guidelines, which the regulators have to draw up, as well as
the network codes, which the TSOs have to establish, were
the main subjects discussed in the Forum in 2010.
Particular attention was paid to pilot framework guidelines
projects relating to the allocation of capacity, balancing and
tariff harmonisation. As regards drawing up framework guidelines on capacity allocation, the Forum welcomed the
work done by ERGEG (cf. paragraph 6.4.6 below), which
resulted in a final proposal submitted by the regulators to
the European Commission at the end of 2010.
Among the items placed on the Forum agenda by the European Commission were also measures designed to ensure
the security of the natural gas supply in the future. This
resulted in the publication of Regulation (EU) No 994/2010
of 20 October 2010 concerning measures to safeguard
security of the gas supply and repealing Council Directive
2004/67/EC (see paragraph 2.5.A of this report). The launch
of a new comitology process relating to the principles of
congestion management (implementing European Parliament and Council Regulation (EC) No 715/2009 of 13 July
2009 on conditions for access to the natural gas transmission networks and repealing Regulation (EC) No 1775/2005)
130 http://www.energy-regulator.eu/portal/page/portal/ACER_HOME/The_Agency/Work_programme/ACER%20Work%20Programme%202011.pdf.
131 The conclusions reached by the Forum and all related documents are available on the European Commission website: www.ec.europa.eu/energy/gas_electricity/forum_gas_madrid_en.htm.
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6. The CREG
was also dealt with. Moreover, particular attention was paid
to the issue of investment. In this context, the European
Commission published an “Energy Infrastructure Package”
to enable better identification and support projects of European interest.
6.4.4. The Florence Forum
The European Electricity Regulatory Forum, also known as
the Florence Forum, is a platform for consultation on the
development of an internal electricity market whose participants include the European Commission, the member
states and the European regulators. The 18th and 19th meetings of the Forum were held on 10 and 11 June and on 13
and 14 December 2010132.
The following items were discussed at both meetings: the
internal electricity market, specifically including the work
concerning the Framework Guidelines included in the third
European energy package, market integrity and transparency, the development of transmission infrastructures and
regional initiatives. The final meeting dealt with the implementation of the European Agency for the cooperation
of energy regulators (paragraph 6.4.2 above) and its work
programme.
As regards drawing up the framework guidelines, at its last
meeting the Forum welcomed the work of ERGEG (paragraph 6.4.6 below) concerning the framework guidelines
on connection to the network and those on capacity allocation and congestion management. The Forum stressed the
importance of the work performed in the field of capacity
allocation and congestion management for the creation of a
robust framework for market coupling based on price. The
Forum particulary stressed the importance of clearly specifying the target model for the Intraday mechanism for the
allocation of transmission capacity in the framework guidelines on capacity allocation and congestion management.
The Forum also welcomed the good coupling results based
on volumes recently put in place between the Central West
Europe region (CWE) and the Scandinavian region and
agreed that establishing coupling based on price in northwestern Europe (CWE, Scandinavia and United Kingdom)
scheduled for 2012 is the first stage in putting in place pricebased coupling that would extend across Europe.
As regards the development of transmission infrastructure,
the Forum underlined the key role of the regulators and
TSOs in putting in place a new pan-European instrument for
energy security and infrastructure. In particular, the Forum
encouraged the proposal relating to the establishment of a
platform dedicated to electricity highways, which would be
run by the European Commission in conjunction with ENTSO-E (European Network of TSOs for Electricity) and the
regulators.
With regard to regional initiatives, the Forum recalled their
key role in putting in place the internal electricity market.
6.4.5. The London Forum
The CREG took part in the third Citizens’ Energy Forum, also
known as the London Forum, on 21 and 22 October 2010133.
The particular feature of this Forum, organised by the European Commission together with CEER, as compared with
those in Florence (paragraph 6.4.4 above) or Madrid (paragraph 6.4.3 above) is that it is intended to enable consumers
and their organisations to participate in an active way in the
debates. The European Commission is represented by DG
ENER (Energy) and DG SANCO (Health and Consumers). The
regulatory authorities and public authorities from the member
states were also in attendance. The sector was represented
amongst others by Eurelectric, Eurogas, Geode and CEDEC.
It is also worth noting the presence of independent and autonomous ombudsmen and sector-based complaints services.
The Forum welcomed the conclusions of the Informal Energy Council which met on 6 and 7 September 2010, with
consumer protection as one of the main issues, and during
which the Belgian presidency examined, at ministerial level,
the growing phenomenon of energy poverty, proposed to
increase the importance of the London Forum and approved the European Commission proposal to prepare a report
aimed at establishing:
• a network of energy ombudsmen with competence
for matters of consumer protection;
• a list of existing and future European practices likely
to contribute directly or indirectly to consumers’
interests;
• a framework definition of vulnerable customers.
The following four main topics were discussed at the 2010
London Forum:
• the complaint handling procedure, through the approval of the “Guidelines of Good Practice on Customer
Complaint Handling, Reporting and Classification”;
• billing, through the approval of the “Status Review on
Implementation of the European Commission Billing
Guidance for Good Practice”;
• smart meters, through the approval of “the draft recommendations on smart metering”;
132 T he conclusions reached by the Forum and all the related documents are available on the European Commission website:
http://ec.europa.eu/energy/gas_electricity_forum_electricity_florence_en.htm.
133 The conclusions reached by the Forum and all the related documents are available on the European Commission website:
http://ec.europa/energy/gas_electricity/forum_electricity_florence_en.htm.
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6. The CREG
• the competitive market for the end customer, through
the approval of “the Guidelines on Retail Market Monitoring Indicators”.
CEER presentations were given, prepared in the Working Group
and its Task Forces, in which the CREG took an active part.
The 2010 London Forum asked CEER to undertake the following actions with a view to the 2011 Forum:
• submit a draft of a status review on the implementation of the Guidelines of Good Practice on Dispute
Settlement/Complaint Handling;
• continue to cooperate within the working groups set
up by the European Commission on smart meters,
put forward recommendations on regulation regarding
smart meters and in particular their functionalities and
services;
• draft a benchmarking report on the role and responsibility of the energy regulators when increasing awareness among and protecting (vulnerable) consumers;
• draft “guidelines of good practice” for price comparison instruments;
• update the “guidelines of good practice” on switching”.
Finally, the DG SANCO gave an exclusive presentation at the
Forum of its study entitled “The functioning of retail electricity markets for consumers in the European Union”134,
which is based on the results of the second “consumer
markets scoreboard”135. A fourth “scoreboard” has since
then been published (in November 2010) by the DG SANCO.
The DG SANCO also announced during the London Forum
that at the European Council meeting of 3 December 2010
it would communicate a Commission Staff Working Paper
on the operation of retail electricity markets for consumers in the European Union136 and an energy policy for
consumers137.
6.4.6. The CREG within CEER and ERGEG
The CREG is a member of both CEER and of ERGEG. ERGEG is an independent consultative group for the electricity and gas sectors made up of energy regulators that was
created to advise and assist the European Commission with
a view to consolidating the internal energy market. CEER is
a cooperation structure made up of these same regulators
together with Norway and Iceland which prepares the work
of ERGEG.
The activities prepared by CEER in 2010138 specifically include the third energy legislative package, the preparation
and creation of an Agency for the Cooperation of Energy
Regulators (ACER, cf. paragraph 6.4.2 above) and the establishment of framework guidelines intended ultimately to
lead to network codes.
The CEER “Energy Package” working group organised three
workshops among national Regulation authorities, including
one attended by the European Commission. These workshops enabled the national regulatory authorities to develop
harmonised solutions to the problems encountered in the
transposition of the third energy package.
While waiting for ACER to become fully operational, CEER
set a series of preparatory steps necessary for its creation
(cf. paragraph 6.4.2 above) and undertook to make as much
progress as possible in drafting the framework guidelines,
the objective of which is to create a non-binding regulatory
framework to establish an integrated electricity and gas
network in Europe. Both in the Gas working group (Capacity
Allocation Mechanism) and in the Electricity working group
(Grid Connection), members worked first and foremost on
pilot framework guidelines, which also highlighted a series
of observations and recommendations on the procedure
to be followed when drafting these guidelines. These pilot
framework guidelines were drawn up by the CEER/ERGEG
working group on electricity, networks and market, which
is co-chaired by the CREG, and communicated to the European Commission as planned.
This working group was also asked to draw up framework
guidelines on capacity allocation and congestion management, in which CREG was particularly involved, an initial
version of which was published and submitted for consultation in September and October 2010. An improved version,
taking into account the results of the consultation, was to
be sent to the European Commission in February 2011. Finally, the working group was also able to start work on the
framework guidelines relating to system operation in 2010.
Moreover, the ten regulators concerned are to consult one
another with regard to their participation in the various
working groups set up in the context of the North Sea
Countries’ Offshore Grid Initiative. On 3 December 2010,
representatives of the ten member states involved signed
a Memorandum of Understanding and both ENTSO-E and
the ten national regulatory authorities concerned signed a
letter of intent139.
134 This study is available at http/:ec.europa.eu/conumsers/strategy/docs/retail_electricity_full_study_en.pdf.
135 http://ec.europa.eu/consumers/strategy/facts_en.htm;
136 http://www.europarl.europa.eu/registre/docs_autres_institutions/commission_europeenne/sec/2010/1409/COM_SEC(2010)1409_EN.pdf.
137 http://ec.europa.eu/energy/gas_electricity/doc/forum_citizen_energy/sec(2010)1407.pdf. The conclusions reached by the European Council of 3 December 2010 can be consulted via the following links: http://www.consilium.europa.eu/uedocs/cms_data/docs/pressdat/en/tran/118188.pdf and http://register.consilium.europa.eu/pdf/en/10/st16/st16300.en.pdf.
138 These activities are mentioned in the CEER Work Programme of 2010 (http://www.energy-regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATINS/Work_Porgramme/Tab1/C09-WPDC-18-03_public-WP2010_10-Dec-09.pdf).
139 https://www.entsoe.eu/fileleadmin/user_upload/_library/news/MoU_North_Seas_Grid/01203_MoU_of_the_North_Seas_Countries_Offshore_Grid_Initiative.pdf.
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6. The CREG
CEER paid particular attention to smart meters and smart
grids in various working groups. For instance, in 2010 the
RMC working group drew up Guidelines of Good Practice
on Regulatory Aspects of Smart Metering for Electricity and
Gas which were to be approved by the CEER general meeting in early 2011. After this, the “Customer Working Group”
(new name: Retail Market and Customer Working Group)
considered the Guidelines of Good Practice on Complaint
Handling, the Billing Status Review and the Guidelines of
Good Practice on Retail Market Indicators.
In 2010, the Financial Services Working Group concentrated
most of its attention on possible fraud mechanisms in the
energy sector and in particular on derived products. In this
context, contacts with the financial regulators organisation
(CESR) were continued. This involved examining the need
to adopt rules specifically for the sector on matters that are
not governed by the (EC) “market abuse” directive or the
EC directive on financial instruments markets, but which
are nevertheless important in the context of transactions
that take place on the energy markets. At the end of 2010
the European Commission published a draft regulation on
this subject140. The Financial Services Working Group also
produced a study on the basis of the questionnaire sent out
to the national regulatory authorities with regard to VAT. The
aim here is to provide an overview of the extent to which
the national regulatory authorities study the VAT fraud mechanisms at the time of transactions on the electricity or
gas market.
The CREG also took part in answering the questionnaires
sent out by CEER with regard, among other things, to VAT
fraud, the procedure for adopting framework guidelines, climate change, CAPEX, compliance monitoring, the quality of
regulation and the retail market (European Commission study). These questionnaires result in status reviews, position
papers or other summarising documents, presenting not
only the differences and similarities between the various
member states but also the extent to which European legislation is implemented by the member states.
Finally, CEER deployed actions at international level through
the Florence School of Regulation, the IERN (International
Energy Regulation Network) and the ICER (International
Confederation of Energy Regulators), with a view to sharing
knowledge and experiences with energy regulators beyond
the borders of the European Union as well. It is also worth
mentioning the regular contacts with the Federal Tariff Service in Russia and the CEER’s participation in the EU-Russia
dialogue on gas supplies.
6.4.7. The CREG and the regional regulators
The concertation between the national regulator (CREG)
and three regional regulators (BRUGEL, CWaPE, VREG) or
‘Forbeg’ continued in 2010. Six plenary meetings were held.
The VREG took the chair in the first half of 2010 and the
CREG during the second half of the year.
Over time, various working groups have been set up within
the Forbeg concertation structure. In 2010, the CREG chaired the working groups on gas, the exchange of information
and the complaints procedure.
The gas working group met five times in 2010 and tackled
the following subjects, among others: the L-gas market,
natural gas supplies to Belgium, the code of conduct, the
third European energy package, the technical regulations
and DSOs’ connection contracts.
The exchange of information working group met five times
in 2010 and, as it does every year, took care of a publication
by the four regulators on the development of the electricity
and natural gas markets141. This publication notes, among
other things, a spectacular increase in the number of takeovers (Essent by RWE, Nuon by Vattenfall, SPE by EDF) and
describes the consequences of the merger between SUEZ
and GDF (first year when Distrigas operated independently
of GDF SUEZ, modification of the Fluxys shareholding body),
as well as the implementation of the agreements reached
under the Pax Electrica II (swaps, drawing rights, production
capacity transfer). The working group also looked into the issue of the extent to which complementary elements could
be included in future versions of the joint publication with
regard to data on supplier switch and renewable energy.
The exchange of information working group also discussed
the possibility of aligning the structures of the annual activities reports from the regulators to the structure of the
benchmark report drawn up in the context of the national
reports passed on to the European Commission and used
as basis for the ERGEG 2010 Status Review of the Liberalisation and Implementation of the Energy Regulatory Framework142. Eventually, the CREG alone decided to adapt the
structure of its annual report along these lines.
The complaints handling working group convened to meet
in the attendance of the Federal Energy Ombudsman, given
that he has been fully operational since 2010 (cf. paragraph
6.4.8 below).
At the Forbeg plenary meeting, the progress of the work
on the European third energy package and the launch of the
European Agency for the Cooperation of Energy Regulators
140 http://ec.europa.eu/energy/gas_electricity/markets/doc/com_2010_0726_en.pdf.
141 http://www.creg.info/pdf/Presse/2010/compress27042010fr.pdf.
142 http://www.energy-regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/NATIONAL_REPORTS/National%20Reporting%202010/C10-URB-34-04_StatusReview2010_v101201.pdf.
88
6. The CREG
(ACER, cf. paragraph 6.4.2 above) were mentioned regularly.
Particular attention was also paid to the work of the European Commission and major publications were mentioned.
Moreover, the CREG debriefed meetings of the General
Assembly of CEER (cf. paragraph 6.4.6 above) and ACER
and gave presentations on the subject of the proposed new
transmission model, the North Sea Grid Initiative and the
coupling of the Central West Europe – Nordic market for
electricity. The VREG, meanwhile, systematically debriefed meetings of the CEER Customer Working Group and,
together with the VREG, the CREG arranged wide-ranging
debriefing on the London Forum (cf. paragraph 6.4.5 above).
Moreover, in 2010 the CREG continued to improve the
contents of its website with a view to keeping consumers
and market players better informed.
6.4.9. Participation of CREG members as speakers
at seminars
In addition to the presentations given as part of its legal
missions (including within CEER), members of the CREG
attended a number of seminars as speakers in 2010. In its
capacity as a member of the CERRE (Centre on Regulation
in Europe), the CREG also took part in certain activities run
and organised by this body.
In addition, the following topics were covered within Forbeg in 2010: smart networks (policy platform, round table),
private networks, MIG (cf. rules and procedures designed
to enable the efficient transfer of data between the various
players on the gas and electricity markets), injection rates,
automatic granting of the social rate, recharging terminals
for electric vehicles, fuel mix issue and a joint letter from the
four regulators to the Minister for Energy recommending
the abolition of the current mechanism for exemption from
the federal contribution.
6.4.8. Handling questions and complaints
In its reasoned opinion of 24 June 2010 (infringement No
2009/2211), the European Commission notes that Belgium
has not created a structure at federal level to settle complaints or to provide for the reimbursement or compensation of end customers. Nor has it been demonstrated that
such a mechanism exists in the Brussels Region and the
Flemish Region. The justification given by Belgium of the
existence of a Litigation Chamber, a federal mediator and regulations in the Brussels Region and in the Flemish Region
was deemed inadequate in this respect by the European
Commission. In the view of the Management Board, only an
amendment of the law can provide a satisfactory response
to these objections143.
In 2010, the CREG took part in five meetings organised by
the federal mediation service for energy. The main aim of
these meetings was to organise the procedure for handling
complaints that come under the jurisdiction of the energy
regulators (CREG, CWaPE, VREG, BRUGEL) or the Federal
Public Service for the Economy. As part of this cooperation,
the CREG has analysed a number of complaints received by
the mediator from end customers.
The procedure for appointing the French-speaking federal
mediator for energy is still under way. A call for applications
was renewed in April 2010.
143 Study (F)100824-CDC-985.
89
6. The CREG
Table 23: Overview of presentations given by the CREG in 2010
Organising authority
Febeliec
FLAME
Florence school
of Regulation
AFG
SRBE
SRBE
European Energy Markets ‘10
VSGP
World Energy Congress
DEMSEE 2010
Instituut voor Milieu- en
Energierecht (IMER)
FEBEG
E.on
Febeliec
SRBE
CMS De Backer
Forbeg
EMART
AFG
PCG
Title of seminar
Successfully managing Gas
demand, Supply, Prices,
Regulation & Investment
in Europe’s Globalising Gas
& LNG Markets
Is there a need for
regulation: what,
why and how?
L’accès des tiers au stockage
Les réseaux intelligents
Journée d’étude SRBE sur
les Smart Grids
7th international conference
on the European Energy
market
Grid Intelligence
Title of presentation
Gedragscode II
Exploring the latest investment developments
in Belgium
Date
13/01/2010
04/03/2010
Early findings from the 2009 ERGEG
monitoring survey on natural gas hub
regulation
Le cas de la Belgique
Les réseaux intelligents: rêve technocratique
ou nécessité de demain ? Et le
consommateur résidentiel dans tout cela ?
Smart Grids, technocratische droom of
de noodzaak van morgen? En wat met de
residentiële gebruikers?
Smart grids en smart meters: Comment et
pourquoi ? Evolution ou révolution ?
Possible impact of electric cars on electricity
spot prices
04/03/2010
04/06/2010
17/06/2010
17/06/2010
25/06/2010
Toepassing van tarieven voor injectie op het
09/09/2010
distributienet
Responding now to global
Possible use of electric cars as balancing
15/09/2010
challenges
instrument
Smart grids and smart
Smart grids en smart meters: How and
23/09/2010
meters
why? Évolution ou révolution ?
12/10/2010
Permanente vorming klimaat- Liberalisering in netwerksectoren
en energierecht
GEREGULEERDE MEERJARENNETTARIEVEN
ELEKTRICITEIT EN GAS
Vervoersmodel aardgas
12/10/2010
13/10/2010
14/10/2010
Le changement de paradigme du réseau
20/10/2010
Gestion de la Demande
électrique
d’Électricité dans un
environnement libéralisé
avec intégration croissante
d’énergies renouvelables
La production d’énergie
Toepassing van tarieven voor injectie op het
20/10/2010
décentralisée
distributienet
Consultatie vervoersmodel aardgas
25/10/2010
24/11/2010
EMART Energy 2010-12-22
Framework guidelines Capacity Allocation
& Congestion Management: the calculation
and allocation of transmission capacities (au
nom de l’ERGEG)
L’accès des tiers au stockage Le cas de la Belgique
25/11/2010
01/12/2010
The annual European Power Elaboration of the framework guidelines:
The cases of Grid connection & Capacity
generation strategy summit
Allocation and Congestion Management
2010
Source: CREG
90
6. The CREG
6.5. The CREG finances
6.5.1. The federal contribution
The federal contribution is a surcharge levied on the quantity
of gas and electricity consumed in Belgium. This contribution is used to finance the various funds run by the CREG,
which are discussed in paragraph 6.5.2 below.
The quantity of electricity taken up on the transmission system in 2010 increased compared with 2009 but has not yet
returned to the level recorded before the economic crisis,
notably owing, for industrial customers, to the significant
increase in own consumption (cf. paragraph 3.2.1 of this
report). As regards the quantity of natural gas used in 2010,
it appears that this has withstood the crisis better since it
has returned to the level recorded before the crisis (cf. paragraph 4.2.1 of this report).
the TSO and the electricity companies (with regard to the federal contribution relating to deliveries prior to 1 July 2009)
respectively amounted to € 53,975,032 and € 5,969,269
which have yet to be divided among the six funds for the
2010 financial year.
n
Supplying the funds
As in previous years, the expected amounts of the federal
contribution for the year 2010 consisted of the basic amount
of each fund for the current year and possibly a supplementary amount to offset the shortfall from previous years. Taken
as a whole, the revenue recorded from the federal contribution for electricity was 14 % less than the amounts expected in 2010. The shortfall in electricity revenue for the various
funds compared with the amounts expected, including the
aforementioned supplement, is therefore as follows:
Table 24: Shortfalls recorded in the funds in 2010 (€)
A. The federal contribution for gas
Each quarter the CREG bills the holders of a natural gas supply permit operating on the Fluxys transmission system144
or one fourth of the annual requirements of the gas funds.
These suppliers finance the CREG fund (and its reserve),
the social energy fund, the protected customers fund and
the heating grant fund directly. Consequently the receipts
booked by the CREG for each of these funds exactly match
the expected amounts. As at 31 December 2010, however,
the suppliers still owed a total of € 539,133.
n
Annual adjustment
Each year, a comparison between the amount claimed by the
CREG and the amount that suppliers were actually able to
invoice their customers during the previous year (2009) gives
rise to adjustments. For the CREG, social energy and protected customers funds, this is an adjustment in favour of the
funds of € 221,024, € 627,558 and € 712,147 respectively.
However, for the heating grant fund, the adjustment amounts
to € 27,073 in favour of the suppliers.
B. The federal contribution for electricity
Each quarter the TSO, Elia, pays into the CREG single federal contribution fund the contribution it has invoiced to its
customers in the previous quarter. The amount collected is
then divided among the CREG, social energy, denuclearisation, greenhouse gas, protected customers and heating
grant funds.
As at 31 December 2010, the total amount in the federal
contribution fund stood at € 61,768,390. The federal contribution and the degressivity certified in the last quarter by
CREG
1,409,600
Social energy
5,925,841
Denuclearisation
16,932,764
Greenhouse gases
8,256,337
Protected customers
8,211,463
Heating grant
1,554,540
Source: CREG
n
Exemption and degressivity
With the “cascade” levy system in force since July 2009
(cf. 2009 Annual Report, paragraph 6.1.2, p. 66), the electricity companies have in principle been billed upstream of the
cascade for the entire federal contribution, whereas they
are only able to recover the total amount from their end customers subject to the deduction, where appropriate, of the
exemption and degressivity measures. Provision is therefore made for these companies to claim the refund of these
two measures from the CREG every quarter.
In 2010, the CREG therefore booked the sums of
€ 18,797,840 and € 37,266,184, corresponding respectively
to the exemptions from greenhouse gases and denuclearisation contributions granted by these companies to their
end customers. Refunds to electricity companies are made
directly using the resources available in these two funds.
During the same period, the Federal Public Service for Finance provided the sum of € 45,488,235 for the CREG to
enable it to cover the degressivity refunded to suppliers. In
addition to this amount and in accordance with the Electricity
Act145, the CREG also received the sum of € 3,000,000 from
ONDRAF/NIRAS (the Belgian agency for radioactive waste
144 As at 31 December 2010, twelve suppliers were active on the transmission grid (SPE having taken over the customers of EDF Belgium on 1 October 2010).
145 Article 21bis, § 3, de la loi du 29 avril 1999 relative à l’organisation du marché de l’électricité, tel que modifié par la loi-programme du 22 décembre 2008.
91
6. The CREG
and enriched fissile materials), taken from the BP1/BP2 fund
and € 2,650,000 from the operating fund of Belgoprocess
(company specialising in the management of radioactive
waste and the decommissioning of nuclear facilities). As
the degressivity certified for 2010 as a whole amounts to €
49,055,950, the sum of € 2,082,285 will have to be refunded
to the Federal Public Service for Finance in 2011.
As at 31 December 2010, the overall amount available in the
fund stood at € 11,913,364, including interest and amounts
still to be distributed from the federal contribution fund. This
amount will not be sufficient to pay the entire fourth instalment for 2010 to the Public Centres for social well-being at
the start of 2011.
n Amounts
The Denuclearisation Fund
irrecoverable
Finally, it should be stressed that the growing number of
unpaid electricity bills is impacting on the federal contribution fund managed by the CREG. In fact, every year the
CREG settles with the electricity companies the flat-rate
amounts (0.7 %) corresponding to the increase in the federal contribution which they have applied to offset the federal
contribution billed which may not have been paid to them by
the end customer. The irrecoverable amounts of the federal
contribution refunded by the CREG to certain companies in
this way are higher than the amounts received from other
companies. Overall, for 2009 the amounts irrecoverable represent 1.3 % of the receipts from the federal contribution.
The accumulated shortfall of € 1,036,677 had to be cleared
in 2010 by means of a levy from the various funds financed
by the federal contribution.
The CREG Fund
This fund, which is supplied exclusively by the federal contribution charged by the electricity sector, should have stood
at € 55,000,000 for 2010 (cf. 2009 Annual Report, paragraph 6.2.3, p. 68), plus € 23,843,807 to offset shortfalls
from the past and repay the European institutions. Income
of € 99,177,227 was recorded in the fund, from which €
37,266,184 should be deducted as exemptions refunded to
the electricity companies. Apart from the payment of the
balance from 2009 (€ 27,330,000), in 2010 the CREG was
therefore only able to pay to ONDRAF/NIRAS the sum of
€ 17,750,000 out of the sum of € 41,250,000 which it should
have received in 2010 to fulfil its denuclearisation task.
The payment arrears to ONDRAF/NIRAS is still increasing,
particularly since the schedules for receipt of the federal
contribution paid by the TSO and refund to the suppliers of
exemption from the “denuclearisation” contribution meant
that the CREG was obliged to maintain operating fund of
€ 10,000,000 to make these reimbursements within the
deadlines set by law.
The partial cover of the total operating costs of the CREG
was set by Royal Decree on 9 March 2010 confirmed by the
Act of 29 December 2010 at € 15,146,140 for the year 2010.
As at 31 December 2010, the total amount in the fund stood
at € 25,734,402, including the amounts still to be distributed
from the federal contribution fund.
The CREG accounts for 2010 are set out in detail in paragraph 6.5.3.
The Greenhouse Gases Fund
6.5.2. The funds
The Social Energy Fund
For 2010, a total of € 49,511,288 was provided to help the Public Centres for social well-being with their task of providing
guidance and financial social support in the field of energy.
This sum was made up of € 28,785,633 from the electricity
sector and € 20,725,655 from the natural gas sector. However, these amounts were supplemented by € 6,508,211 and
€ 9,526, respectively to offset the shortfalls of the past and
repay the European institutions. The total revenue eventually booked for electricity in 2010 was € 29,368,003. The
planned amount for the gas fund was achieved. In addition
to the balance payable to the Public Centres for social wellbeing for 2009 (€ 11,072,576), the cash assets only made
it possible to redistribute € 38,187,847 of the € 40,922,327
required by the Federal Public Planning Service for Social
Integration in 2010.
92
This fund, which is supplied exclusively by the federal contribution charged by the electricity sector, should have stood at
€ 28,683,289 for the year 2010, plus € 10,650,589 to offset the
shortfalls from the past and repay the European institutions.
Income of € 49,875,381 was booked in the fund, from which
the sum of € 18,797,840 has to be deducted as exemptions
refunded to electricity companies. Unlike the denuclearisation fund, which is used in full as soon as it is supplied, there
are sums which are not used immediately and which enable
the reimbursement to suppliers of the exemption from the
greenhouse gases contribution while awaiting receipt of the
federal contributions paid by the TSO.
As is the case every year, the CREG paid the sum of
€ 2,300,000 for the year 2011 in advance into the organic budget fund of the Federal Public Service for the Environment,
intended for the annual financing of the federal policy on the
6. The CREG
reduction of greenhouse gas emissions, which it manages.
In addition, following the modification of Article 12 of the “federal electricity contribution” Royal Decree, the CREG may
owe the Federal Public Service for the Environment additional
sums146 amounting to € 2,000,000 for 2010 and € 1,300,000
for 2011.
Every year the greenhouse gases fund also prefinances the
sum of € 11,550,000 corresponding to the VAT due on the
annual amount to be paid to ONDRAF/NIRAS. The VAT authorities refunded to the CREG the quarterly sums thus paid.
As at 31 December 2010, the overall amount in the fund
stood at € 41,265,845, including interest and the amounts
still to be distributed from the federal contribution fund.
No additional amounts were transferred this year from the
greenhouse gases fund to the Kyoto Joint Implementation/
Clean Development Mechanism fund (Kyoto JI/CDM). It
should be remembered that this fund sets aside resources
which are intended specifically to fund projects to reduce
emissions of greenhouse gases abroad, enabling Belgium
to acquire emission quotas with a view to attaining its targets in the context of the Kyoto protocol. In 2010, the sum of
€ 26,339,099 was drawn on the Kyoto JI/CDM fund for the
purchase of CO2 emission credits.
As at 31 December 2010, the total amount in the Kyoto JI/
CDM fund stood at € 97,013,391, including interest.
92,639,735 respectively, including interest and sums still to
be distributed from the federal contribution fund.
The fund for flat-rate reductions for heating using natural gas and electricity
For the year 2010 a total sum of € 9,988,339 was provided
to enable the financing of the flat-rate discounts provided for
by the programme law of 8 June 2008 for heating with natural gas and electricity. This amount consists of € 6,891,954
from the electricity sector and € 3,096,385 from the natural
gas sector. These amounts are, however, supplemented respectively by € 1,984,069 and € 1,424 to offset the shortfalls
of the past and repay the European institutions. Total income
of € 7,321,483 was eventually booked in 2010 for electricity.
The amount planned for gas was actually recorded. Apart
from the payment of the 2009 balances relating to grants for
electricity (€ 4,147,782) and natural gas (€ 775,000), no other
payments were paid into the organic budget fund run by the
Directorate-General for Energy in 2010. In fact, noting the
absence of any legal basis for its use during the year 2010,
the CREG suspended all additional payments.
The balance as at 31 December 2010, amounting to
€ 7,072,905, corresponds to the amounts recorded as at
that date for the electricity TSO and the natural gas companies and that had not been paid into the organic budget
fund. A legal allocation of these funds will need to be found
once the annual adjustments with the natural gas suppliers
have been made in 2011.
The Protected Customers Funds
For the year 2010, the needs of these funds, defined by
the Royal Decree of 9 March 2010 confirmed by the Act
of 29 December 2010, should have stood at a total of €
64,000,000 for electricity and € 33,900,000 for natural gas,
to which should have been added € 202,362 and € 20,949
respectively to repay the European institutions. Ultimately,
only € 55,990,899 was booked in the electricity fund in
2010. As regards the natural gas fund, however, the planned
sum was in fact recorded.
Repayments to companies in the sector that supplied protected household customers at maximum social rates in
2010 amounted to € 452,207 for electricity suppliers and
€ 135,749 for natural gas suppliers. The small amount of
repayments in 2010 is due in particular to the fact that most
of the dossiers are incomplete and to the fact that the Royal
Decrees on ‘protected customer claims’ had not yet been
published at the end of 2010.
As at 31 December 2010, the total amounts of the two
funds for electricity and gas stood at € 132,108,438 and €
The fund to offset the loss of revenue suffered by the
municipalities
Further to the negative opinion No 48.153/1/3 from the
Council of State on 27 April 2010, the Flemish authorities
managing the funds of the municipalities, with which the
CREG was in negotiation with regard to the settlement
for 2009 with the Flemish municipalities (cf. 2009 Annual
Report, paragraph 6.2.7, p. 69) was obliged to waive this
transaction.
The CREG itself therefore undertook the settlement of
€ 12,856,802 with the municipalities to which sums were
due, having recovered the sum of € 88,565 from municipalities liable for payments.
As at 31 December 2010, the sum of € 574,280 corresponding to the interest collected since 2005 remains in the
accounts of the CREG as the interest on the fund capital is
only supposed to be used to reimburse suppliers for charges
linked to their prefinancing during the period from August
2005 to 31 July 2006 (Article 9, § 3 of the Ministerial Decree
146 Act of 29 December 2010 containing various provisions (Belgian Official Journalof 31 December 2010).
93
6. The CREG
of 13 May 2005 implementing Article 22bis of the Electricity
Act). However, these reimbursements have already been
effected. A legal allocation of these funds will need to be
found.
6.5.3. The accounts for 2010
On the one hand, the CREG was only able to take note of
the prolonged effects of the economic crisis on this income
from the electricity sector. On the other hand, it observed
charges that remain high further to recourse against its decisions. Taking this as a starting point, it has brought its staff
costs and other operating expenses under control by not
replacing members of staff who have left the CREG over the
year and by reducing the calls made upon external consultants to carry out studies. Both staff costs and other operating expenses therefore remained within the limits set by
the budget.
The total charges of the CREG for the 2010 financial year
consequently amounted to just € 13,595,714, which corresponds to 91 % of the total budget initially planned
(€ 14,860,634, without bringing the reserve up to the required level and excluding off-budget expenses). It should be
noted, however, that legal fees relating to appeals lodged
against decisions taken by the CREG (€ 646,952) are up on
the previous year and they alone account for over 21 % of
the total operating costs for 2010.
Although the total income from the electricity sector only
amounted to 88 % of the expected amounts, at the end of
2010 the CREG nevertheless benefited from two salutary
extraordinary receipts. On the one hand, it recovered its
2009 membership subscription to a non-profit association
following the winding up of this association (€ 99,500) and
on the other hand it received a settlement further to the
adjustment resulting from the structural reductions in the
social charges for the years 2008 and 2009 (€ 611,656).
The income and expenditure of the CREG are broken down
between the two energy sectors.
For the 2010 financial year, thanks to the extraordinary income referred to above, the surplus income collected by
the CREG compared with its actual charges amounted to
€ 1,115,908, divided between surpluses of € 246,742 in
favour of the electricity sector and € 869,166 in favour of
the natural gas sector.
The surplus booked in 2010 for the electricity sector will be
used entirely for the partial re-establishment of the sector
94
reserve. In fact, a great deal was drawn from this reserve in
2009 (cf. 2009 Annual Report, paragraph 6.3, p. 69) to cover
the shortfall in the electricity sector.
The surplus booked in 2010 for the natural gas sector will
have to be repaid to the gas companies in 2011 by means of
an adjustment. This surplus includes the excess surcharges
actually recovered in 2009 by the natural gas suppliers from
their customers (€ 221,024) which were adjusted in 2010.
However, the amount of revenue earned by the natural gas
suppliers in 2010 was not yet known as at 31 December 2010.
Finally, the adjustment of the surplus collected by the CREG
relating to the natural gas sector, which was noted in the
CREG accounts in 2009 (cf. 2009 Annual Report, paragraph
6.3, p. 69) was effected in favour of the natural gas sector.
6. The CREG
Table 25: Income statement as at 31 December 2010 (€)
Personnel costs
Salaries and charges
Variation provisions employment agreements for Management Board members
Variation provisions for holiday bonuses
Temporary staff
Recruitment costs
Training, seminars
Leasing company cars
Value added tax
Bodies
Indemnities, General Council (attendance fees and various expenses)
“Personnel costs” sub-total
External experts
External studies
Communication service
Translators, Auditor, external payroll service provider
Legal fees relating to lawsuits
Operating costs
Rental and charges - premises
Parking facility rental
Building maintenance and security
Equipment maintenance and servicing
Documentation
Telephone, post, Internet
Office supplies
Costs of meetings and expenses
Travel expenses (including abroad)
Membership of associations
Insurance, taxes and sundry costs
Value added tax
Depreciation costs
Depreciation on tangible fixed assets
Depreciation on leasing
Financial costs
Financial charges on leasing and loans
Other
“Other operating costs” sub-total
TOTAL CHARGES
Income (surcharges and fees)
Operating cost surcharges
Gas suppliers’ adjustment, year n-1
CREG adjustment electricity, year n
CREG adjustment gas, year n
Other fees
Financial income
Income from current assets
Other financial income
Extraordinary income
Other extraordinary income
TOTAL INCOME
RESULT FOR FINANCIAL YEAR
2010
10,459,025
9,937,241
71,266
–930
20,714
9,500
106,882
254,612
59,740
74,927
74,927
10,533,952
1,029,523
217,793
49,535
115,243
646,952
1,914,169
913,042
65,885
120,785
47,198
108,660
43,987
58,706
98,564
57,244
61,207
146,234
192,657
109,119
98,831
10,288
8,951
2,773
6,178
3,061,762
13,595,714
12,830,023
13,707,590
221,024
–246,742
–869,166
17,317
6,599
6,542
57
759,092
759,092
13,595,714
0
2009
10,121,156
9,587,997
–128,243
119,048
1,432
121,429
104,097
237,483
77,913
59,250
59,250
10,180,406
949,232
316,205
19,310
101,132
512,585
2,017,658
894,822
59,182
115,901
48,286
122,873
44,472
60,936
84,769
52,256
134,981
225,350
173,830
107,585
90,502
17,083
5,142
3,013
2,129
3,079,617
13,260,023
13,205,883
12,911,059
730,574
818,481
–1,261,574
7,343
19,239
19,212
27
34,901
34,901
13,260,023
0
Source: CREG
95
6. The CREG
Table 26 : Balance sheet as at 31 December 2010 (€)
FIXED ASSETS
Intangible and tangible fixed assets
IT and telephone equipment
Security equipment, video surveillance
Office furniture and decoration
Building refurbishment
Leasing
Leased equipment
Financial fixed assets
Various guarantees
Cautions diverses
CURRENT ASSETS
Amounts receivable within one year
Trade debtors
Other amounts receivable
Cash at bank and in hand
Federal contribution fund
CREG fund
Social Energy Fund
Greenhouse Gases Fund
Denuclearisation Fund
Kyoto Fund JI/CDM
Protected Customers Fund - Electricity
Protected Customers Fund - Gas
Municipalities Fund
Heating Grant Fund
Cash
Deferrals and accruals
TOTAL ASSETS
LIABILITIES
CAPITAL AND RESERVES
Profit brought forward
CREG sector reserve
Electricity
Gas
Provisions
Employment agreements for Management Board members
AMOUNTS PAYABLE
Amounts payable at more than one year
Leasing obligations
Amounts payable within one year
Current portion of amounts payable at more than one year
Trade debts
Taxes, salaries and social charges payable
Advances received
Various debts
Social Energy Fund
Greenhouse Gases Fund
Denuclearisation Fund
Kyoto Fund JI/CDM
Protected Customers Fund - Electricity
Protected Customers Fund - Gas
Municipalities Fund
Heating Grant Fund
Federal contribution and degressivity
Accruals and deferrals
TOTAL LIABILITIES
96
2010
2009
209,575
57,635
7,016
24,601
120,323
20,962
20,962
608
608
208,593
56,758
10,524
15,901
125,410
31,250
31,250
608
608
585,202
39,473
545,729
417,815,247
61,768,390
3,219,311
5,051,910
31,290,683
1,389,895
97,005,861
119,942,061
92,217,966
574,125
5,353,666
1,377
1,147,040
419,778,634
476,840
37,566
439,274
311,184,143
30,319,624
3,711,463
6,963,232
8,278,569
672,104
120,803,456
68,609,361
57,758,420
13,305,152
761,441
1,321
1,022,246
312,923,680
2010
2009
1,314,222
1,441,323
750,304
691,019
1,314,222
1,196,185
503,562
692,623
290,314
219,048
17,799
17,799
3,342,391
6,641
1,808,100
1,527,650
0
413,366,683
11,913,364
41,265,845
25,734,402
97,013,391
132,108,438
92,639,735
574,280
7,071,524
5,045,704
5,902
419,778,634
24,440
24,440
3,932,180
9,339
1,754,473
2,166,868
1,500
305,853,256
10,643,449
12,815,526
5,284,657
120,880,809
76,594,477
58,028,392
13,305,704
1,634,724
6,665,518
384,349
312,923,680
Source: CREG
6. The CREG
6.5.4. The company auditor’s report on the financial
year closed on 31 December 2010
In accordance with the assignment entrusted to us by the
Management Board pursuant to Article 9, §1 of the Royal
Decree of 10 October 2001 (on approval of the internal
rules), we have the honour of reporting to you on the accounts for the past financial year. This report contains our
opinion on the accounts as well as the required additional
statements and information.
Unqualified audit opinion on the accounts
We have audited the accounts of the Commission for the
financial year ended 31 December 2010, prepared in accordance with the valuation rules adopted by the Management
Board. These accounts are summarised in a balance sheet,
the total of which amounts to 419,778,634 EUR and an income statement, the balance of which stands at 0 EUR, in
accordance with the Royal Decrees of 24 March 2003 on
the financing of the Commission, with the total income and
charges standing at 13,595,714 EUR.
The Management Board is responsible for the preparation
of the accounts. This responsibility includes: designing,
implementing and maintaining internal control relevant to
the preparation of the accounts that are free from material
misstatement, whether due to fraud or error; selecting and
applying appropriate valuation rules; and making accounting
estimates that are reasonable in the circumstances.
Our responsibility is to express an opinion on these accounts based on our audit. We conducted our audit in accordance with the auditing standards applicable in Belgium, as
issued by the Institute of Registered Auditors (Institut des
Reviseurs d’Entreprises / Instituut der Bedrijfsrevisoren).
Those standards require that we plan and perform the audit
to obtain reasonable assurance whether the accounts are
free from material misstatement, whether due to fraud or
error.
In accordance with the above-mentioned auditing standards, we considered the Commission’s accounting system
as well as its internal control procedures. We have obtained from the Management Board and the Commission’s
officials, the explanations and information necessary for
executing our audit procedures. We have examined, on a
test basis, the evidence supporting the amounts included
in the accounts. We have assessed the appropriateness of
valuation rules and the reasonableness of the significant
accounting estimates made by the Commission. We believe
that these procedures provide a reasonable basis for our
opinion.
financial year give a true and fair view of the assets, the
financial position and the results of the Commission in accordance with the valuation rules adopted by the Management Board.
Additional statements and information
We would like to supplement our report with the following
additional statements and information, which do not modify
our audit opinion on the accounts:
• Without prejudice to formal aspects of minor importance, the accounting records were maintained in accordance with the general rules of the Act of 17 July
1975 on corporate accounting.
• As specificied in the annual report drawn up by the
Management Board, the amount of the adjustment
for the 2010 financial year between the gas suppliers
and the Commission, calculated in accordance with
Article 5, §2 of the Royal Decree of 24 March 2003 on
the financing of the Commission by the gas market,
was unknown on the date on which the accounts of
the Commission as per 31 December 2010 were established and could therefore not be taken into account.
The adjustment relating to the previous financial year
was duly booked however.
•
We have not established any infringements of the
“Electricity” and “Gas” Acts or their implementing
decrees as regards transactions referred to in the accounts of the Commission.
Brussels, 28 January 2011
André KILESSE
Auditor
In our opinion, the balance sheet for the year ended 31
December 2010 and the income statement for the 2010
97
6. The CREG
6.6. List of acts of the CREG during the year 2010
Tariff decisions
(B)628E/19 à (B)628E/22 • INTER-ENERGA (elektriciteit) : beslissingen over het tariefvoorstel met budget voor de regula04.02.2010 → 16.12.2010
toire periode 2009-2012, over de initiële waarde van het gereguleerd actief, over de vraag tot
goedkeuring van het tariefvoorstel met budget voor het exploitatiejaar 2007 en van het vervolledigde tariefvoorstel met budget voor de 2 laatste jaren van de regulatoire periode 2009-2012
(B)628G/15 à (B)628G/16 • INTER-ENERGA (aardgas) : beslissingen over het tariefvoorstel met budget voor de regulatoire
04.02.2010 → 16.12.2010
periode 2009-2012 en over de vraag tot goedkeuring van het vervolledigde tariefvoorstel met
budget voor de 2 laatste jaren van de regulatoire periode 2009-2012
(B)629E/09
16.12.2010
• INTER-ENERGA (elektriciteit) : beslissing over de vraag tot goedkeuring van het vervolledigde
tariefvoorstel met budget voor de netten met een transmissiefunctie voor het laatste jaar van
de regulatoire periode 2008-2011
(B)631E/19 à (B)631E/21 • IVEG (elektriciteit) : beslissingen over het tariefvoorstel met budget voor de regulatoire pe04.02.2010 → 16.12.2010
riode 2009-2012, over de vraag tot goedkeuring van het tariefvoorstel met budget voor het
exploitatiejaar 2007 en van het vervolledigde tariefvoorstel met budget voor de 2 laatste jaren
van de regulatoire periode 2009-2012
(B)631G/15 à (B)631G/16 • IVEG (aardgas) : beslissingen over het tariefvoorstel met budget voor de regulatoire periode
04.02.2010 → 16.12.2010
2009-2012 en over de vraag tot goedkeuring van het vervolledigde tariefvoorstel met budget
voor de 2 laatste jaren van de regulatoire periode 2009-2012
(B)632E/16 à (B)632E/18 • PBE (elektriciteit) : beslissingen over het tariefvoorstel met budget voor de regulatoire periode
04.02.2010 → 16.12.2010
2009-2012, over de vraag tot goedkeuring van het tariefvoorstel met budget voor het exploitatiejaar 2007 en van het vervolledigde tariefvoorstel met budget voor de 2 laatste jaren van de
regulatoire periode 2009-2012
(B)633E/19 à (B)633E/21 • INFRAX WEST (elektriciteit) : beslissingen over het tariefvoorstel met budget voor de regula04.02.2010 → 16.12.2010
toire periode 2009-2012, over de vraag tot goedkeuring van het tariefvoorstel met budget voor
het exploitatiejaar 2007 en van het vervolledigde tariefvoorstel met budget voor de 2 laatste
jaren van de regulatoire periode 2009-2012
(B)633G/15 à (B)633G/16 • INFRAX WEST (aardgas) : beslissingen over het tariefvoorstel met budget voor de regulatoire
04.02.2010 → 16.12.2010
periode 2009-2012 en over de vraag tot goedkeuring van het vervolledigde tariefvoorstel met
budget voor de 2 laatste jaren van de regulatoire periode 2009-2012
(B)634E/14 à (B)634E/15 • GASELWEST (elektriciteit) : beslissingen over de saldi betreffende het exploitatiejaar 2009
21.10.2010 → 25.11.2010
(B)634G/14 à (B)634G/15 • GASELWEST (aardgas) : beslissingen over de saldi betreffende het exploitatiejaar 2009
21.10.2010 → 25.11.2010
(B)635G/14 à (B)635G/15 • IMEA (aardgas) : beslissingen over de saldi betreffende het exploitatiejaar 2009
21.10.2010 → 25.11.2010
(B)636E/14 à (B)636E/15 • IMEA (elektriciteit) : beslissingen over de saldi betreffende het exploitatiejaar 2009
21.10.2010 → 25.11.2010
(B)637E/14 à (B)637E/15 • IMEWO (elektriciteit) : beslissingen over de saldi betreffende het exploitatiejaar 2009
21.10.2010 → 25.11.2010
(B)637G/14 à (B)637G/15 • IMEWO (aardgas) : beslissingen over de saldi betreffende het exploitatiejaar 2009
21.10.2010 → 25.11.2010
• Confidential
98
6. The CREG
(B)638E/14 à (B)638E/15 • INTERGEM (elektriciteit) : beslissingen over de saldi betreffende het exploitatiejaar 2009
21.10.2010 → 25.11.2010
(B)638G/14 à (B)638G/15 • INTERGEM (aardgas) : beslissingen over de saldi betreffende het exploitatiejaar 2009
21.10.2010 → 25.11.2010
(B)639E/14 à (B)639E/15 • IVEKA (elektriciteit) : beslissingen over de saldi betreffende het exploitatiejaar 2009
21.10.2010 → 25.11.2010
(B)639G/14 à (B)639G/15 • IVEKA (aardgas) : beslissingen over de saldi betreffende het exploitatiejaar 2009
21.10.2010 → 25.11.2010
(B)640E/14 à (B)640E/15 • IVERLEK (elektriciteit) : beslissingen over de saldi betreffende het exploitatiejaar 2009
21.10.2010 → 25.11.2010
(B)640G/14 à (B)640G/15 • IVERLEK (aardgas) : beslissingen over de saldi betreffende het exploitatiejaar 2009
21.10.2010 → 25.11.2010
(B)641E/14 à (B)641E/15 • SIBELGAS (elektriciteit) : beslissingen over de saldi betreffende het exploitatiejaar 2009
21.10.2010 → 25.11.2010
(B)641G/14 à (B)641G/15 • SIBELGAS (aardgas) : beslissingen over de saldi betreffende het exploitatiejaar 2009
21.10.2010 → 25.11.2010
(B)642E/10
23.12.2010
• AIEG (électricité) : décision relative aux soldes rapportés concernant l’exercice d’exploitation
2009
(B)643E/10 à (B)643E/11 • AIESH (électricité) : décisions relatives aux soldes rapportés concernant l’exercice d’exploita25.11.2010 → 23.12.2010
tion 2009
(B)644E/20
04.02.2010
• TECTEO (électricité) : décision relative à la proposition tarifaire accompagnée du budget pour
la période régulatoire 2009-2012
(B)645G/14 à (B)645G/15 • ALG (gaz naturel) : décisions relatives à la demande d’approbation de la proposition tarifaire
02.09.2010
accompagnée du budget pour l’exercice d’exploitation 2007 ainsi qu’à l’application des tarifs
pour le même exercice d’exploitation 2007 et à la constatation d’un bonus ou d’un malus
résultant des tarifs appliqués pour l’exercice d’exploitation 2008
(B)646E/14 à (B)646E/16 • RÉGIE DE L’ÉLECTRICITÉ DE LA VILLE DE WAVRE (électricité) : décisions relatives à la
29.04.2010 → 14.10.2010
constatation de l’existence d’un bonus ou d’un malus résultant des tarifs appliqués au cours
de l’exercice d’exploitation 2008 et pour l’exercice d’exploitation 2006
(B)655E/10
02.12.2010
• SIBELGA (électricité) : décision relative aux soldes rapportés concernant l’exercice d’exploitation 2009
(B)655G/10
02.12.2010
• SIBELGA (gaz naturel) : décision relative aux soldes rapportés concernant l’exercice d’exploitation 2009
(B)658E/15 à (B)658E/16 • ELIA : décisions relatives aux soldes rapportés concernant l’exercice d’exploitation 2009
12.05.2010 → 25.06.2010
(B)658E/17
22.10.2010
• ELIA : décision relative au retrait de la décision (B)030320-CDC-130 du 20 mars 2003 relative
aux conditions générales de la convention provisoire pour l’utilisation non exclusive du réseau
Elia par des utilisateurs éligibles raccordés aux réseaux de distribution établis en région wallonne ou en région bruxelloise
• Confidential
99
6. The CREG
Other acts
(F)100204-CDC-929
04.02.2010
• Étude relative à l’impact possible de la voiture électrique sur le système électrique belge
Studie over de mogelijke impact van de elektrische auto op het Belgische elektriciteitssysteem
(F)100107-CDC-934
07.01.2010
• Étude relative aux composantes des prix de l’électricité et du gaz naturel
Studie over de componenten van de elektriciteits- en aardgasprijzen
(A)100114-CDC-935
14.01.2010
• Advies over de aanvraag van de N.V. Fluxys voor de toekenning van een bijvoegsel bij de
vervoersvergunning voor de vervoersinstallaties DN600 LD Antwerpen (SIBP) – Schelle en
DN400 HD Antwerpen (GCA) – Hoboken
(F)100114-CDC-936
14.01.2010
• Étude relative au développement d’un marché régional compétitif du gaz naturel à faible pouvoir calorifique
Studie over de uitbouw van een regionale competitieve markt voor laagcalorisch aardgas
(A)100121-CDC-937
21.01.2010
• Avis relatif à la demande de la S.A. Fluxys pour l’octroi d’une autorisation de transport A3233745 pour la modification de la station de compression à Haccourt (Oupeye)
(B)100114-CDC-938
14.01.2010
• Décision relative à la demande d’approbation de modification du programme indicatif de transport de la S.A. Fluxys relatif à ses activités d’acheminement pour la période 2010-2011
Beslissing over de vraag tot goedkeuring van de wijziging van het indicatief vervoersprogramma van de N.V. Fluxys voor wat betreft haar overbrengingsactiviteiten voor de periode
2010-2011
(B)100121-CDC-939
21.01.2010
• Décision sur la proposition (à nouveau) adaptée de contrat standard d’accès du client final au
réseau de transport de gaz naturel (appelé le « contrat standard de raccordement »)
Beslissing over het (andermaal) aangepaste voorstel van standaardcontract voor de toegang
van de eindafnemer tot het aardgasvervoersnet (het zgn. ”standaard aansluitingscontract”)
(A)100121-CDC-940
21.01.2010
• Advies over de aanvraag van de N.V. Fluxys voor de toekenning van een vervoersvergunning
voor de vervoersinstallaties DN250 HD Evergem (Caelbeek - Doornzele) en DN150 HD Evergem (Doornzele) – Algist Bruggeman
(B)100121-CDC-941
21.01.2010
• Onderzoek over de controle op de redelijkheid van de directe en indirecte kosten van de permanente expert en de overige kosten van Sibelgas cvba
(E)100204-CDC-942
04.02.2010
• Proposition relative à la nécessité d’un renouvellement des autorisations individuelles de production de SPE S.A., suite à son changement de contrôle par le rachat de SEGEBEL S.A. par
EDF Belgium S.A.
(F)100129-CDC-943
29.01.2010
• Étude relative à l’aperçu des contrats à prix fixes sur le marché résidentiel de l’électricité et
du gaz
Studie over het overzicht van de contracten tegen vaste prijzen op de residentiële markt voor
elektriciteit en gas
(F)100128-CDC-944
28.01.2010
• Étude sur une première estimation du coût des mesures visées à l’article 7 de la loi du 29 avril
1999 relative à l’organisation du marché de l’électricité
Studie over de eerste raming van de kostprijs van de maatregelen bedoeld in artikel 7 van de
wet van 29 april 1999 betreffende de organisatie van de elektriciteitsmarkt
(F)100211-CREG-945
11.02.2010
• Etude relative à la possible connexion entre le terminal GNL de Dunkerque et le réseau de
transport de gaz naturel belge
Studie betreffende de mogelijke verbinding tussen de LNG-terminal te Duinkerke en het Belgisch aardgasvervoersnet
(A)100211-CDC-946
11.02.2010
• Avis relatif à la demande d’approbation des modifications proposées par Belpex concernant le
règlement de marché de Belpex
Advies over de aanvraag tot goedkeuring van de door Belpex voorgestelde wijzigingen aan het
Belpex marktreglement
• Confidential • Published on www.creg.be
100
6. The CREG
(F)100218-CDC-947
18.02.2010
+ erratum 12/05/2010
• Étude relative au marché belge à court terme d’électricité Belpex et à l’utilisation de la capacité
aux interconnexions avec la France et les Pays-Bas en 2009
Studie over de Belgische kortetermijnmarkt voor elektriciteit Belpex en het gebruik van de
capaciteit op de interconnecties met Frankrijk en Nederland in 2009
(F)100909-CDC-948
09.09.2010
• Étude relative à la qualité du paramètre Nc
Studie over de kwaliteit van de Nc-parameter
(B)100211-CDC-949
11.02.2010
• Beslissing om [confidentiel] geen administratieve geldboete op te leggen
(B)100211-CDC-950
11.02.2010
• Beslissing om [confidentiel] geen administratieve geldboete op te leggen
(A)100225-CDC-951
25.02.2010
• Avis relatif à l’octroi d’une autorisation individuelle de fourniture de gaz naturel à ENLOGS
Energy Logistics and Services GmbH
(T)100225-CDC-952
25.02.2010
• Verslag van de feitelijke vaststellingen betreffende de directe en indirecte kosten van de permanente expert en de overige kosten van Sibelgas cvba
(A)100311-CDC-953
11.03.2010
• Advies over de aanvraag van de N.V. Fluxys voor de toekenning van een bijvoegsel bij de vervoersvergunning A322-54 voor de vervoersinstallatie Herent (Winksele) – Compressiestation
(A)100305-CDC-954
05.03.2010
• Avis relatif à la demande de la S.A. Fluxys pour l’octroi d’une autorisation de transport A3233751 concernant une DN250 BP Charleroi – IGH Viaduc 2
(A)100318-CDC-955
18.03.2010
• Avis relatif à l’indépendance d’un administrateur indépendant au sein du conseil d’administration du gestionnaire du réseau national de transport d’électricité
(A)100401-CDC-956
01.04.2010
• Avis relatif à l’octroi d’une autorisation individuelle de fourniture de gaz naturel à Gas Natural
Europe SAS
(A)100401-CDC-957
01.04.2010
voor de vervoersinstallaties DN150 HD Leuven (Wilsele ontspanning – Kesselstraat) en DN150
HD Leuven (Wilsele Kesselstraat) – AB Inbev
(F)100401-CDC-958
01.04.2010
• Étude relative à l’achat d’énergie pour la compensation des pertes d’énergie par les gestionnaires de réseau de distribution entre 2006 et 2008
Studie over de aankoop van energie voor de compensatie van de netverliezen door de distributienetbeheerders tussen 2006 en 2008
(F)100401-CDC-959
01.04.2010
• Étude relative à l’éventuelle suppression ou exonération des tarifs d’injection pour les installations de production sur la base de l’énergie renouvelable et de la cogénération qualitative
Studie betreffende de mogelijke schrapping of vrijstelling van injectietarieven voor de productieinstallaties op basis van hernieuwbare energie en kwalitatieve WKK
(B)100401-CDC-960
01.04.2010
Beslissing over de vraag tot goedkeuring van de wijziging van het indicatief vervoersprogramma van de N.V. Fluxys, voor wat betreft haar overbrengingsactiviteiten voor de periode
2010-2011
(F)100415-CDC-961
15.04.2010
• Étude relative à la demande d’élargissement du champ d’application de l’arrêté royal du 16 juillet 2002 relatif à l’établissement de mécanismes visant la promotion de l’électricité produite à
partir de sources d’énergie renouvelables aux installations de cogénération reliées au réseau
de transport fédéral
Studie over de vraag tot uitbreiding van het toepassingsgebied van het koninklijk besluit van
16 juli 2002 betreffende de instelling van mechanismen voor de bevordering van elektriciteit
opgewekt uit hernieuwbare energiebronnen, op kwalitatieve warmtekrachtinstallaties aange
sloten op het federaal transmissienet
101
6. The CREG
(F)100416-CDC-962
16.04.2010
• Étude relative aux modifications à apporter à la loi du 29 avril 1999 relative à l’organisation
du marché de l’électricité en vue d’améliorer le fonctionnement et le suivi du marché de
l’électricité
Studie over wijzigingen aan te brengen aan de wet van 29 april 1999 betreffende de organisatie van de elektriciteitsmarkt voor het verbeteren van de werking en de opvolging van de
elektriciteitsmarkt
(B)100422-CDC-963
22.04.2010
• Décision relative à la modification des conditions générales des contrats de responsable d’accès proposés par le gestionnaire du réseau de transport d’électricité aux utilisateurs du réseau
Beslissing over de wijziging van de algemene voorwaarden van de contracten van toegangsverantwoordelijke aangeboden door de transmissienetbeheerder voor elektriciteit aan de
netgebruikers
(B)100429-CDC-964
29.04.2010
• Décision relative aux règles complémentaires pour le calcul de la marge à calculer afin de
définir les prix maximaux d’électricité à appliquer aux clients non protégés dont le contrat de
fourniture a été résilié
Beslissing over de nadere regels betreffende de berekening van de marge te berekenen voor
de bepaling van de maximumprijzen elektriciteit toe te passen op niet-beschermde gedropte
klanten
(B)100429-CDC-965
29.04.2010
• Décision relative aux règles complémentaires pour le calcul de la marge à calculer afin de
définir les prix maximaux du gaz naturel à appliquer aux clients non protégés dont le contrat
de fourniture a été résilié
Beslissing over de nadere regels betreffende de berekening van de marge te berekenen voor
de bepaling van de maximumprijzen aardgas toe te passen op niet-beschermde gedropte
klanten
(F)100520-CDC-966
20.05.2010
• Étude relative aux différents mécanismes de soutien de l’électricité verte en Belgique
Studie over de verschillende ondersteuningsmechanismen voor groene stroom in België
(Z)100422-CDC-967
22.04.2010
• Rapport comparatif des objectifs formulés dans la note de politique générale de la CREG et
des réalisations de l’année 2009
Vergelijkend verslag van de doelstellingen geformuleerd in het beleidsplan van de CREG en
van de verwezenlijkingen van het jaar 2009
(F)100506-CDC-968
06.05.2010
• Étude sur la structure de coûts de la production d’électricité par les centrales nucléaires en
Belgique
Studie over de kostenstructuur van de elektriciteitsproductie door de nucleaire centrales in
België
(B)100512-CDC-969
12.05.2010
• Décision relative à la demande d’approbation de modification du programme indicatif de transport de la S.A. Fluxys, relatif à ses activités de stockage, pour la période 2010-2011
Beslissing over de vraag tot goedkeuring van de wijziging van het indicatief vervoersprogramma van de N.V. Fluxys, voor wat betreft haar opslagactiviteiten, voor de periode 2010-2011
(E)100603-CDC-970
03.06.2010
• Voorstel betreffende de toekenning van individuele vergunningen voor de vestiging van twee
installaties voor de productie van elektriciteit op de site van Dilsen door DILS-ENERGIE N.V.
(C)100527-CDC-971
27.05.2010
• Proposition d’arrêté royal portant modification de l’article 7, §2, de l’arrêté royal du 16 juillet
2002 relatif à l’établissement de mécanismes visant la promotion de l’électricité produite à
partir de sources d’énergie renouvelables
Voorstel van koninklijk besluit tot wijziging van artikel 7, §2, van het koninklijk besluit van 16
juli 2002 betreffende de instelling van mechanismen voor de bevordering van elektriciteit
opgewekt uit hernieuwbare energiebronnen
(F)100610-CDC-972
10.06.2010
• Étude relative à la faisabilité de l’instauration d’une tarification progressive de l’électricité en
Belgique
Studie betreffende de haalbaarheid van de invoering van een progressieve prijszetting van
elektriciteit in België
102
6. The CREG
(B)100617-CDC-973
17.06.2010
+ erratum 15/07/2010
Beslissing over de vraag tot goedkeuring van de wijziging van het indicatief vervoersprogramma van de NV Fluxys, voor wat betreft haar overbrengingsactiviteiten voor de periode
2010-2011
(F)100610-CDC-974
10.06.2010
• Étude complémentaire à l’étude (F)060309-CDC-537 relative à l’impact du système des quotas d’émissions de CO2 sur le prix de l’électricité en Belgique en 2009
Studie aanvullend bij studie (F)060309-CDC-537 over de impact van het systeem van CO2emissierechten op de elektriciteitsprijs in België in 2009
(A)100624-CDC-975
24.06.2010
• Avis relatif à la demande de la S.A. Fluxys pour l’octroi d’un avenant à l’autorisation de transport A322-2826 pour le prolongement de la canalisation DN250 HP Mons (Obourg-Nimy)
(A)100708-CDC-976
08.07.2010
• Avis relatif à l’octroi d’une autorisation individuelle de fourniture de gaz naturel à natGas
Aktiengesellschaft
(F)100708-CDC-977
08.07.2010
• Étude relative à la facturation des tarifs d’injection pour les producteurs décentralisés en cas
de tarifs reflétant les coûts de raccordement et de tarification de l’utilisation du réseau
Studie betreffende de aanrekening van injectietarieven voor decentrale producenten in geval
van kostenreflectieve aansluitingstarieven en tarifering voor het gebruik van het net
(F)100708-CDC-978
08.07.2010
• Studie betreffende de opmerkingen over het artikel “Nuclear Market Power: Taxation or Liberalization?” mede geschreven door professor Proost (KULeuven)
08.07.2010
• Rapport annuel 2010 de la Belgique à la Commission européenne
(R)100715-CDC-979
15.07.2010
• Lignes directrices concernant la distinction entre activités régulées et non régulées du gestionnaire de réseau de distribution
Richtlijnen over de scheiding tussen gereguleerde en niet gereguleerde activiteiten van de
distributienetbeheerder
(B)100715-CDC-980
15.07.2010
• Beslissing betreffende de vraag tot goedkeuring van de wijziging van het contract voor het aankopen van groenestroomcertificaten tussen de N.V. Elia System Operator en de N.V. Belwind
(B)100812-CDC-981
12.08.2010
netgebruikers
(B)100826-CDC-982
26.08.2010
• Décision sur la demande d’approbation de la méthode d’évaluation et de la détermination de
la puissance de réserve primaire, secondaire et tertiaire pour 2011
Beslissing over de vraag tot goedkeuring van de evaluatiemethode voor en de bepaling van het
primair, secundair en tertiair reservevermogen voor 2011
(RA)1008246-CDC-983
26.08.2010
• Rapport relatif au caractère manifestement déraisonnable ou non des prix offerts à Elia System
Operator NV pour la fourniture de services auxiliaires pour l’exercice d’exploitation 2011
(F)101105-CDC-984
05.11.2010
• Étude relative aux modifications à apporter à la loi du 12 avril 1965 relative au transport de
produits gazeux et autres par canalisations en vue d’améliorer le fonctionnement et le suivi du
marché du gaz naturel et conformément à la directive 2009/73/CE du Parlement européen et
du Conseil du 13 juillet 2009 concernant des règles communes pour le marché intérieur du gaz
naturel et abrogeant la directive 2003/55/CE
Studie over de wijzigingen aan te brengen aan de wet van 12 april 1965 betreffende het vervoer van gasachtige producten en andere door middel van leidingen voor het verbeteren van
de werking en de opvolging van de aardgasmarkt en in overeenstemming met de Richtlijn
2009/73/EG van het Europees parlement en de Raad van 13 juli 2009 betreffende gemeen
schappelijke regels voor de interne markt voor aardgas en tot intrekking van Richtlijn 2003/55/
EG
103
6. The CREG
(F)100824-CDC-985
24.08.2010
• Étude relative aux objections de la Commission européenne telles que décrites dans son avis
motivé du 24 juin 2010 (infraction n° 2009/2211)
Studie over de bezwaren van de Europese Commissie zoals beschreven in haar met redenen
omkleed advies van 24 juni 2010 (overtreding n° 2009/2211)
(F)101105-CDC-986
05.11.2010
• Étude relative aux modifications à apporter à la loi du 29 avril 1999 relative à l’organisation du
marché de l’électricité en vue d’améliorer le fonctionnement et le suivi du marché de l’électricité et conformément à la Directive 2009/72/CE du Parlement européen et du Conseil du
13 juillet 2009 concernant des règles communes pour le marché intérieur de l’électricité et
abrogeant la Directive 2003/54/CE
Studie over de wijzigingen aan te brengen aan de wet van 29 april 1999 betreffende de organisatie van de elektriciteitsmarkt voor het verbeteren van de werking en de opvolging van de
elektriciteitsmarkt en in overeenstemming met richtlijn 2009/72/EG van het Europees Parlement en de Raad van 13 juli 2009 betreffende gemeenschappelijke regels voor de interne
markt voor elektriciteit en tot intrekking van Richtlijn 2003/54/EG
(F)100902-CDC-987
02.09.2010
• Étude relative à l’impact de l’arrêt de centrales nucléaires sur le prix de vente de l’électricité
au client final domestique
Studie over de impact van de stopzetting van de kerncentrales op de verkoopprijs van elektriciteit aan de huishoudelijke eindafnemer
(B)100930-CDC-988
30.09.2010
netgebruikers
(B)100930-CDC-989
30.09.2010
• Décision relative à la demande d’approbation du programme indicatif de terminalling 20112012 de la S.A. Fluxys LNG
Beslissing over de vraag tot goedkeuring van het indicatief terminallingprogramma 2011-2012
van de N.V. Fluxys LNG
(A)100930-CDC-990
30.09.2010
• Avis relatif à la demande d’approbation des modifications proposées par Belpex au règlement
de marché de Belpex
Advies over de aanvraag tot goedkeuring van de door Belpex voorgestelde wijzigingen aan het
Belpex marktreglement
(F)101208-CDC-991
08.12.2010
• Étude relative à la comparaison entre les prix payés par Elia System Operator S.A. pour l’achat
d’énergie en compensation des pertes actives sur ses réseaux régionaux avec les prix de
l’énergie payés par les grands clients industriels au cours de l’exercice d’exploitation 2009
(F)101014-CDC-992
14.10.2010
• Étude relative à la relation entre les coûts et les prix des importateurs, des revendeurs et
des fournisseurs sur le marché belge résidentiel et industriel du gaz naturel sur la période
2007-2009
Studie over de verhouding tussen de kosten en de prijzen van invoerders, doorverkopers
en leveranciers op de Belgische residentiële en industriële aardgasmarkt tijdens de periode
2007-2009
(B)101007-CDC-993
07.10.2010
• Décision relative à la demande d’approbation de la proposition de la S.A. Elia System Operator
de modification des méthodes de gestion de la congestion et des méthodes pour l’allocation
aux responsables d’accès de la capacité disponible pour les échanges d’énergie avec le réseau
français et avec le réseau néerlandais, telles qu’établies dans le cadre de l’initiative régionale
Centre-Ouest européenne
Beslissing over de aanvraag tot goedkeuring van het voorstel van de NV Elia System Operator
tot wijziging van de methodes voor congestiebeheer en de methodes voor de toekenning aan
de toegangsverantwoordelijken van de capaciteit die beschikbaar is voor energie-uitwisselingen met het Franse en het Nederlandse net, zoals vastgelegd in het kader van het Centraal
West-Europees regionaal initiatief
104
6. The CREG
(A)101014-CDC-994
14.10.2010
• Avis relatif au projet de plan de développement 2010-2020 de la S.A. Elia System Operator
Advies over het ontwerp van ontwikkelingsplan 2010-2020 van de N.V. Elia System Operator
(F)101007-CDC-995
07.10.2010
• Étude relative à la comparaison des prix de l’électricité pour un ménage consommant 3.500
kWh d’électricité grise (tarif unique) à Bruxelles, Paris, Berlin, Amsterdam et Londres
Studie over de vergelijking van de elektriciteitsprijzen voor een gezin met een verbruik van
3.500 kWh grijze elektriciteit (enkelvoudig tarief) in Brussel, Parijs, Berlijn, Amsterdam en
Londen
(B)101026-CDC-997
26.10.2010
relative au plan général pour le calcul de la capacité totale de transfert et de la marge de fiabilité du transport et aux méthodes de gestion de la congestion pour les échanges d’énergie
avec le réseau français et avec le réseau néerlandais, telles qu’établies dans le cadre du couplage des marchés de la région Centre-Ouest européenne
Beslissing over de aanvraag tot goedkeuring van het voorstel van de NV Elia System Operator
betreffende het algemeen model voor de berekening van de totale overdrachtcapaciteit en
de transportbetrouwbaarheidsmarge en betreffende de methodes voor congestiebeheer voor
energie-uitwisselingen met het Franse en het Nederlandse net, zoals vastgelegd in het kader
van de marktkoppeling van de Centraal West-Europese regio
(B)101028-CDC-998
28.10.2010
• Décision relative à la demande d’approbation de la proposition de la S.A. Elia System Operator relative aux méthodes de gestion de la congestion et aux méthodes pour l’allocation aux
responsables d’accès de la capacité disponible en journalier sur les interconnexions BelgiqueFrance et Belgique-Pays-Bas au moyen d’enchères implicites faite dans le cadre du couplage
des marchés de la région Centre-Ouest européenne
Beslissing over de aanvraag tot goedkeuring van het voorstel van de NV Elia System Operator betreffende de methodes voor congestiebeheer en de methodes voor het toekennen,
aan de toegangsverantwoordelijken, van de beschikbare dagcapaciteit op de koppelverbindingen België-Frankrijk en België-Nederland via impliciete veilingen, gedaan in het kader van de
marktkoppeling van de Centraal West-Europese regio
(F)101014-CDC-999
14.10.2010
• Étude sur l’accord nucléaire en Allemagne et son application en Belgique
Studie over het nucleair akkoord in Duitsland en de toepassing ervan op België
(E)101014-CDC-1000
14.10.2010
• Proposition relative à l’octroi d’une autorisation de fourniture d’électricité à la Pfalzwerke A.G.
(F)101208-CDC-1001
08.12.2010
• Studie over de vergelijking van de prijzen die Eandis cvba betaalde voor de aankoop van energie
ter compensatie van actieve verliezen op haar distributienetten met de energieprijzen betaald
door de grote industriële klanten tijdens het exploitatiejaar 2009
(A)101021-CDC-1002
21.10.2010
• Avis relatif à la demande de la S.A. Fluxys pour l’octroi d’une autorisation de transport A3233754 concernant une DN300 HP Visé (Quai des Fermettes) – SPE Lixhe (Navagne)
(Z)101028-CDC-1003
28.10.2010
• Note de politique générale pour l’année 2011
Beleidsplan voor het jaar 2011
(F)101021-CDC-1004
21.10.2010
• Étude relative aux composantes des prix de l’électricité et du gaz naturel
Studie over de componenten van de elektriciteits- en aardgasprijzen
(F)101208-CDC-1005
08.12.2010
• Étude relative à la comparaison entre les prix payés par les GRDs mixtes wallons regroupés
au sein de ORES SCRL pour l’achat d’énergie en compensation des pertes actives sur les
réseaux régionaux avec les prix de l’énergie payés par les grands clients industriels au cours
de l’exercice d’exploitation 2009
(C)101208-CDC-1006
08.12.2010
• Proposition sur le calcul de la surcharge destinée à compenser le coût réel net supporté par
le gestionnaire du réseau résultant de l’obligation d’achat et de vente des certificats verts en
2011
(A)101028-CDC-1007
28.10.2010
• Avis relatif à la demande de la S.A. Fluxys pour l’octroi d’une autorisation de transport A3233795 concernant une DN150 HP Lessines-Baxter
105
6. The CREG
(A)101028-CDC-1008
28.10.2010
• Advies over de toekenning van een individuele leveringsvergunning voor aardgas aan Progress
Energy Services BVBA
(E)101202-CDC-1009
02.12.2010
• Voorstel betreffende de toekenning van een vergunning voor de levering van elektriciteit aan
Essent Belgium N.V.
(A)101104-CDC-1010
04.11.2010
voor de vervoersinstallatie DN300 LD Merelbeke (Gaversesteenweg) – Gent (Zwijnaarde
Ringvaart)
(A)101104-CDC-1011
04.11.2010
voor de vervoersinstallatie Dendermonde (Oudegem Paalstraat) – Station Ontspanning
(B)101118-CDC-1012
18.11.2010
• Beslissing over de aanvraag van Belwind voor toekenning van groenestroomcertificaten voor
de elektriciteit opgewekt door windturbines A04, B02, B06, B07 en C02 op de Blighbank
(A)101104-CDC-1013
04.11.2010
+ erratum 08/12/2010
• Avis relatif au projet d’arrêté royal modifiant l’arrêté royal du 20 décembre 2000 relatif aux
conditions et à la procédure d’octroi des concessions domaniales pour la construction et l’exploitation d’installations de production d’électricité à partir de l’eau, des courants ou des vents,
dans les espaces marins sur lesquels la Belgique peut exercer sa juridiction conformément au
droit international de la mer
Advies over het ontwerp van koninklijk besluit tot wijziging van het koninklijk besluit van
20 december 2000 betreffende de voorwaarden en de procedure voor de toekenning van
domeinconcessies voor de bouw en de exploitatie van installaties voor de productie van
elektriciteit uit water, stromen of winden, in de zeegebieden waarin België rechtsmacht kan
uitoefenen overeenkomstig het internationaal zeerecht
(B)101125-CDC-1015
25.11.2010
de elektriciteit opgewekt door windturbines A05, A10, B01, B03, B05, B08, B09, B10, C03,
C04, C05, C06, C07, C09, C10, D01, D02, D03, D04, D05, D06, D07, D10, F03 en F05 op de
Blighbank
(B)101118-CDC-1016
18.11.2010
voor de vervoersinstallatie DN250 HD Brugge (Dudzele P.S. - Oostkerkestraat)
(B)101118-CDC-1017
18.11.2010
• Advies over de aanvraag van de N.V. Fluxys voor de toekenning van een bijvoegsel bij de vervoersvergunning voor de vervoersinstallatie Brugge (Dudzele Oostkerkestraat) - Station
(B)101125-CDC-1018
25.11.2010
relative aux méthodes de gestion de la congestion et aux méthodes pour l’allocation aux responsables d’accès de la capacité disponible sur l’interconnexion Belgique-France
Beslissing over de aanvraag tot goedkeuring van het voorstel van de N.V. Elia System Operator
betreffende de methoden voor congestiebeheer en de methoden voor de toekenning van de
beschikbare capaciteit op de koppelverbinding België-Frankrijk aan de toegangsverantwoordelijken
(B)101125-CDC-1019
25.11.2010
• Décision relative à la modification des conditions générales des contrats de responsable d’accès proposés par le gestionnaire du réseau aux utilisateurs du réseau
Beslissing over de wijziging van de algemene voorwaarden van de contracten van
toegangsverantwoordelijke aangeboden door de transmissienetbeheerder voor elektriciteit
aan de netgebruikers
(F)101202-CDC-1020
02.12.2010
• Étude relative à l’évolution du terme fixe et/ou de capacité dans le réseau de distribution entre
2003 et 2009
Studie over de evolutie van de vaste en/of capaciteitsterm in het distributienettarief tussen
2003 en 2009
(E)101125-CDC-1021
25.11.2010
• Voorstel betreffende de toekenning van een individuele vergunning voor de bouw van een
warmtekrachtkoppelingeenheid door de N.V. Stora Enso Langerbrugge te Langerbrugge (Gent)
106
6. The CREG
(E)101125-CDC-1022
25.11.2010
• Proposition relative à ‘l’octroi d’une autorisation de fourniture à Enovos Luxembourg S.A.
(E)101202-CDC-1023
02.12.2010
• Proposition relative à l’octroi d’une autorisation individuelle relative à l’extension d’une installation de production d’électricité (parc éolien) à Mettet/Fosses-la-Ville par la S.A. Électricité du
Bois du Prince
(B)101202-CDC-1024
02.12.2010
• Décision relative à la modification des conditions générales des contrats de responsable d’accès proposés par le gestionnaire du réseau aux utilisateurs du réseau
netgebruikers
(F)101208-CDC-1025
08.12.2010
• Étude relative aux mécanismes de fixation des prix de l’énergie en vigueur en 2009 au sein
des contrats de fourniture d’électricité des grands clients industriels de Electrabel S.A.
(A)101208-CDC-1026
08.12.2010
• Avis relatif à l’octroi d’une autorisation individuelle de fourniture de gaz naturel à Enovos
Luxembourg S.A.
(B)101223-CDC-1027
23.12.2010
• Décision sur la demande d’approbation de la méthode d’évaluation et de la détermination de
la puissance de réserve primaire, secondaire et tertiaire pour 2011
(B)101223-CDC-1028
23.12.2010
• Décision concernant la proposition de la S.A. Elia System Operator concernant les règles de
fonctionnement du marché relatif à la compensation des déséquilibres quart-horaires pour
l’année 2011
Beslissing over het voorstel van de NV Elia System Operator betreffende de werkingsregels
van de markt voor de compensatie van de kwartieronevenwichten voor 2011
(B)101208-CDC-1029
08.12.2010
• Décision relative à la demande d’approbation du programme indicatif de transport de la S.A.
Fluxys relatif à ses activités d’acheminement pour la période 2011-2012
Beslissing over de vraag tot goedkeuring van het indicatief vervoersprogramma van de NV
Fluxys, voor wat betreft haar overbrengingsactiviteiten voor de periode 2011-2012
(B)101216-CDC-1030
16.12.2010
de elektriciteit opgewekt door windturbines A01, A02, A03, A06, A07, A08, A09, B04, C01,
D09, E01, E02, E03, E04, E05, E06, E07, E08, E09, E10, F02 en F04 op de Blighbank
(A)101216-CDC-1031
16.12.2010
• Advies over de toekenning van een individuele leveringsvergunning voor aardgas aan Essent
Belgium N.V.
107
Chief Editor
Bernard LACROSSE
Rue de l’Industrie, 26-38
1040 Brussels
Design and production
www.inextremis.be
Rue de l’Industrie, 26-38 • 1040 Brussels
Tel. +32 (0)2 289.76.11 • Fax +32 (0)2 289.76.09
E-mail: [email protected] • www.creg.be

annual report 2010

Transcription

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