Regional reporting on electricity interconnections
management and use in 2008 in FUI region
The creation of a single European electricity market has come up against a major obstacle, which is
the lack of sufficient interconnections between Member States. Looking forward to solutions to solve
this major obstacle, National Regulatory Authorities should at least ensure that congestion
management methods currently applied in Europe are efficient.
This regional report on electricity interconnections management and use mainly aims to provide”a
detailed evaluation of the economic efficiency of congestion management methods for the year the
data is taken from” at a regional level. It should ideally complete the Compliance report exercise
undertaken at European level.
This regional report should also help National Regulatory Authorities to reach not only a common
understanding about the functioning of congestion management methods, but also a common view
about the best way to further improve their functioning.
1
Structure of the report
1.
Cross-border flows of the FUI region in 2008..................................................3
Within the region..............................................................................................................................3
Ratio average cross-border capacity / installed generation capacity per country...........................4
2.
Congestion management methods in the FUI region .....................................5
a.
b.
c.
c.
d.
3.
General description of congestion management mechanisms ...........................................7
Table 2 Publication of the rules for allocation and nomination procedures.....................................7
Long and medium term capacities..........................................................................................8
Day-ahead capacities..............................................................................................................10
Intraday capacities..................................................................................................................11
Balancing exchanges .............................................................................................................11
Economic efficiency of congestion management methods .........................13
a.
b.
c.
d.
e.
4.
Global figures ..........................................................................................................................13
Competition indicators ...................................................................................................................13
Long and medium term capacities........................................................................................16
Day-ahead capacities..............................................................................................................19
Consistency of nominations with price differentials.......................................................................19
Intraday capacities..................................................................................................................21
Balancing exchanges .............................................................................................................22
Cross-border balancing reserves ..................................................................................................22
Capacity calculation and management of cross-border flows.....................25
a.
Principles of the capacity calculation method by TSOs .....................................................25
General capacity calculation procedure ........................................................................................25
Evolution of the net transfer capacity ............................................................................................26
Comparison between the NTC and the offers made at the long and medium capacity auctions .27
c.
Costs for ensuring the compatibility of the cross-border flows with grid security.........27
d.
Curtailments occurred in 2008 ..............................................................................................28
2
1. Cross-border flows of the FUI region in 2008
The region comprises two Direct Current interconnectors (cable) the IFA and Moyle
interconnections. The Interconnexion-France-Angleterre (IFA) is currently the only
interconnector in the France-UK-Ireland (FUI) region connecting two Member States and
subject to the requirements of EU legislation and the Congestion Management Guidelines
(CMGs). A joint mechanism for the allocation and use of long-term interconnection capacity
has been in place on IFA since April 2001. Recent improvements on the IFA include the
introduction of a new capacity management system (CMS) in October 2009 in charge of the
allocation and the nomination for the account of NGIL and RTE. At this occasion a new set
of rules was implemented and approved by the regulators.
The Moyle Interconnector is located within the UK, but links the BETTA and SEM markets.
While it is not classified as an interconnector under EU legislation, Moyle has implemented
some of the EU requirements for interconnectors such as third part access rights. Under its
licence Moyle makes capacity available to the market in accordance with access arrangements
which are subject to the approval of NIAUR.
Within the region
(155 GWh)
IR
GB
GWh
299.1 TWh
(700 GWh)
481GWh
11671GWh
FR
495.5 TWh
This graph allows us to assess the importance of cross-border commercial flows with respect to the
total consumption of each country/region.
3
Ratio average cross-border capacity / installed generation capacity per country
1
In the conclusions of the Barcelona summit of March 2002 , the European council agrees the target
for Member States of a level of electricity interconnections equivalent to at least 10% of their installed
production capacity by 2005. The following table enables to monitor whether this ratio is reached.
Interconnectors in the FUI Region
Interconnectors are either operating, under construction or being contemplated within the FUI
region or between the FUI region and other regions are shown below.
Operational
• IFA – Linking France to Great Britain - Operational Since 1986
• Moyle Interconnector – Linking Northern Ireland and Scotland (intra – UK)
Operational Since 2002
Under Construction
• Britned – Linking the Netherlands and GB – To begin Operation in early 2010
• East West – Linking Ireland and GB – To begin Operation in mid 2012
Table 1 Ratio between average interconnection capacities and installed generation capacity
2
France
GB
Ireland
Export capacity /
3
generation capacity
11.9%
2.9%
0.71%
4
Import capacity /
generation capacity
8.2%
2.5%
4%
Source: CER, CRE, Ofgem, NIAUR
First, it must be recalled that the computation does not distinguish the different production
technologies. This means that one MW in wind generation has the same weight as one MW in
nuclear generation.
This table shows that none of the three FUI countries is complying with the 10% minimum
level in the import direction.
New interconnection lines are being built on the Irish-British border and a new interconnector
between the Netherlands and GB is being developed as well.
1
http://ue.eu.int/ueDocs/cms_Data/docs/pressData/en/ec/71025.pdf
2
The export capacity is the hourly average D-2 NTC of all interconnections in the export direction.
3
The generation capacity is the total installed generation plants.
4
The import capacity is the hourly average D-2 NTC of all interconnections in the import direction.
4
Congestion management methods in the FUI region
The France, Ireland and UK electricity REM is led by the British Energy Regulator (Ofgem)
and aims to integrate the national markets in the three countries. Annual electricity
consumption in the France, Ireland and UK electricity REM is about 780 TWh around 30% of
the EU 25 electricity market.
The focus of the work in the FUI region to date has been on transparency, ensuring
compliance of the UK/France interconnector with the CMG requirements and harmonisation
with other European borders and on access of the GB and French system operators
respectively to each other’s balancing markets.
At present, the FUI region contains the following national/cross national markets:
French Market
France has the second biggest wholesale electricity market in the European Union with
volumes on the wholesale market (including cross border imports) amounting to 450 TWh a
year in 2007 (accounting for 127% of French demand), with the majority of power (some
80%) being generated by nuclear power stations. The state-owned utility, Electricité de
France (EDF), dominates the French market in both generation and supply sectors. Most
wholesale activity takes place over the counter through bilateral contracts or through
intermediaries, with the Powernext exchange facilitating day ahead (spot), intra-day and
futures trading. After gate closure, RTE operates the balancing mechanism.
The French market is highly interconnected market with total cross border flows in 2007
equivalent to 16% of domestic consumption. Nuclear plants typically generate at low
marginal cost thus making France a significant exporter of power to its neighbours. In 2007,
France exported 65.5 TWh and imported 10.4 TWh.
France is market price coupled with Belgium and the Netherlands since November 2006.
Powernext began operating intra-day markets in 2007 and in April 2009 Powernext and the
German EEX power exchange merged their entire spot trading activities.
BETTA
The electricity market in GB is known as the British Electricity Trading and Transmission
Arrangements (BETTA). BETTA is a self-dispatch, balancing market with average annual
generation (including cross border imports/exports) of 350 TWh. Market participants are
encouraged to self-balance before gate closure and are required to submit ex ante physical
contract notifications on a half-hourly basis, one hour in advance of each trading half hour.
Generators and suppliers who do not meet their contractual agreements are exposed to
potentially penal system buy prices and system sell prices, both of which aim to reward
participants whose imbalance contributes towards system balance and penalise those that
move the system away from balance.
5
Most trading of electricity takes place either internally (since most generators in GB have
broadly matching supply businesses), through over the counter (OTC) platforms or through
direct ‘structured contracting’, with power exchanges such as APX, which caters for 5% of
electricity traded. These power exchanges operate up to one hour before the physical delivery
of power and constitute the GB day-ahead market. After that point, generation and demand
are balanced by National Grid who act as the only counterparty to trades for the hour before
real time and in real time itself. Transactions under this balancing mechanism account for less
than 2% of electricity traded. National Grid is allowed to trade as a participant in BETTA so
as to reduce its exposure to the penal prices of the balancing mechanism and has an incentive
to do so.
The BETTA market has relatively low levels of interconnection compared with other
European markets, with current levels at 3% of consumption.
SEM
The SEM is the all-island electricity market for Ireland and Northern Ireland with average
generation of 38 TWh a year. The SEM is a gross mandatory pool with day ahead gate
closure into which bids are optimised over the whole day with an ex-post single market
clearing price (SMP). Generators, including interconnector users, submit bids into the SEM
by 10 am on the day before trading. The SEM is an ex-post market, with a significant time
lag between the submission of offers and real time dispatch and the publication of market
prices and quantities (though IC users are notified of their firm dispatch quantities two hours
after gate closure). It is the scheduling and pricing software, in combination with bids by
interconnector users, that determines interconnector flows.
The SEM does not currently have a day-ahead market, one of the consequences of which is
that users of interconnectors in the SEM have no indication of the SMP when it comes to
settling their position in neighbouring markets. Furthermore the SEM does not currently
allow for trading after gate closure.
6
a. General description of congestion management
mechanisms
Table 2 Publication of the rules for allocation and nomination procedures
France – GB
GB – France
Website
http://www.rtefrance.com/htm/fr/offre/telecharge/ifa_access_rules_definitive_issue_v6.pdf
http://www.nationalgrid.com/NR/rdonlyres/5DEEDCE2-52FC-453C-988FF1973B9F696F/37205/IFAAccessRulesv7025September20091.pdf
GB – Ireland
Ireland – GB
http://www.nienergyholdings.com/The_Moyle_Interconnector/Access_Arrangements.php
Source: CER, CRE, Ofgem, NIAUR
Table 3 Main features of allocation procedures
France – GB
GB – France
GB – Ireland
Ireland – GB
Long
term
Explicit
Auctions
Explicit
Auctions
Medium
term
Explicit
Auctions
Explicit
Auctions
Dayahead
Explicit
Auctions
N/A
Intraday
Balancing
N/A
Bilateral contrat
between TSOs (BASA)
N/A
N/A
Source: CER, CRE, Ofgem, NIAUR
7
b. Long and medium term capacities
MAIN CHARACTERISTICS OF THE LONG & MEDIUM TERM CAPACITY RIGHTS: TRADABILITY
AND FIRMNESS
As for any commodity, the price that the market operators are willing to pay to obtain this commodity
depends on the intrinsic characteristics of the product sold: the more reliable the product sold is
(firmness, compensation in the event of curtailment, etc.) and easy-to-use (existence of a secondary
market, nomination procedure, financial/physical nature, etc.), the more valuable it is.
A secondary market is organized on IFA only.
The bilateral transfer allows market participants to trade between themselves whole or part of a
product, i.e. a product can be sliced down by steps of 1MW and of 1hour.
The two resale possibilities allow market players to sell back the acquired capacities to the auctions
held by the TSOs at a shorter timeframe (long term to medium term or long and medium term to daily).
In this case, the whole product is proposed and it cannot be sliced down.
Since the implementation of the new auction rules on IFA in October 2009, the long and medium term
products which have not been nominated are automatically proposed at the concerned daily auction.
The revenues generated by the resale of the non nominated capacities are given back to the initial
holder.
Table 4 Tradability and firmness: main characteristics of the long & medium term capacity
rights
Secondary market
Bilateral
transfers (i.e.
reassignmen
5
ts)
Resale of
long to
medium
term
Resale of
long &
medium term
6
to daily
France – GB
GB – France
GB – Ireland
Ireland – GB
yes, on
request
Yes
Yes, on
request
No
No
No
Compensation
for
curtailments
of allocated
but not
nominated
capacities
Based on the
price paid
according to the
rules explain
below(*)
No (**)
Compensation
for
curtailments
of nominated
capacities
Compensation
in case of
daily auction
cancellation
Based on the
price paid
according to the
rules explain
below(*)
No
No (**)
No
Source: CER, CRE, Ofgem, NIAUR
(*) For the 2007/08 period at the French-English border, the Products are not guaranteed to be firm,
the capacities allocated for different products / periods of time have a target availability rate defined in
the auction specifications. Also the Long-term and daily capacity is not nominated firmly: actors tell
TSOs on D-1 if they intend to nominate acquired capacity. They can change their nominations at any
of the six intraday gate closures, within the intraday transfer limits defined by the interconnection
transmission system operators (RTE on the French side and NGET on the English side).
On this basis, RTE and NGIL calculate, ex-post, the actual availability of each type of capacity for
each market player. The impact of a reduction in long- or short-term capacity thus varies from player
to player, depending on the types of capacity he holds and the nominations he has made.
The TSOs then compare the rate of actual availability of capacity each player holds with the rate of
target availability defined for every type of acquired capacity.
5
Please specify if there is an organized anonymous market, or if bilateral transfers are facilitated with the
publication of the names of capacity holders, or if there are no specific arrangements
6
Please specify if the resale is on request or automatic (i.e. UIOSI)
8
If the actual availability at the end of the product period proves to be below target, holders are
reimbursed by TSOs for the capacity shortfall, based on the price they had paid for the capacity.
Conversely, when actual availability proves to be above target, capacity holders must repay the TSOs
for the additional capacity made available.
st
This mechanism changed on the 1 of October 2009 with the implementation of the new IFA rules.
Long and medium term capacities are now nominated firmly from 16h30 in D-2 until 9h30 on D-1. If
curtailments occur before or after the nomination stage the capacity price will be reimbursed to the
holders. It should be noted that the capacities are curtailed pro rata for all users in the following order:
intraday capacities are reduced first, then the daily capacities and finally the long term capacities.
(**) Capacity on Moyle is not firm. In the event of curtailment, by the system operator, there is no
financial reimbursement for users.
ORGANISATION RESPONSIBLE FOR ALLOCATION, SECONDARY MARKET AND NOMINATION
TSOs concerned by a same border share the following different tasks: auction, resale and nomination.
Table 5 Organization responsible for allocation, secondary market and nomination
Annual
auction
Monthly
auction
Resale
through
subsequent
auctions
Bilateral
transfer
Nomination
NGIL/RTE
NGIL/RTE
(nomination
to one TSO
only at a
time)
France – GB
GB – France
GB – Ireland
Ireland – GB
NGIL/RTE
NGIL/RTE
SONI
SONI
NGIL/RTE
Source: CER, CRE, Ofgem, NIAUR
9
c. Day-ahead capacities
st
Until the 1 October 2009, a band of 24 hours were offered at the daily auctions. There are now
products allocated on an hourly basis.
There are no products allocated at the daily stage on MOYLE.
Table 6 Main characteristics of the day-ahead capacity rights
Secondary market
Bilateral
7
transfers
Resale of daily
capacity to
8
intraday
France – GB
yes, on request
Yes, on request
Not applicable
(NA)
NA
GB – France
GB – Ireland
Ireland – GB
Compensation
for curtailments
of allocated but
not nominated
capacities
Based on the
price paid
according to the
rules explain
above (*)
Compensation for
curtailments of
nominated
capacities
Based on the price
paid according to the
rules explain above
(*)
NA
NA
Source: CER, CRE, Ofgem, NIAUR
(*) see compensation mechanisms described under the long and medium term capacities section
Under the new IFA rules, capacity allocated in the day-ahead auction that is not nominated is, in
practice, lost for the holder due to the “Use-It-Or-Lose-It” rule.
Day-ahead capacity rights cannot be or resold to the next timeframe (intraday) however transfers are
allowed.
Regarding firmness, day-ahead capacity rights are not firm the compensation is the same as the one
described in the long and medium term capacities section.
The application of the “Use-It-Or-Lose-It” rule between the day-ahead stage and the intra-day stage
aims to incentivising market players to use all their capacity in the day-ahead timeframe. This can be
explained by the importance of the day-ahead electricity market compared to the one of the intra-day
market in terms of liquidity, number of participants...
Table 7 Organization responsible for allocation, secondary market and nomination
France – GB
GB – France
GB – Ireland
Ireland – GB
Daily
auction
Resale
through
subsequent
auctions
Bilateral
transfer
Nomination
NGIL/RTE
NGIL/RTE
NGIL/RTE
NGIL/RTE
N/A
N/A
N/A
N/A
Source: CER, CRE, Ofgem, NIAUR
7
Please specify there is an organized anonymous market, or if bilateral transfers are facilitated with the
publication of the names of capacity holders, or if there is no specific arrangements
8
Please specify if the resale is on request or automatic (i.e. UIOSI)
10
c. Intraday capacities
In 2008, no intraday mechanism was in place in the FUI region.
st
Since the 1 of October 2009, the new IFA rules have implemented two explicit auctions to allocate
capacities in the intraday timeframe. The first auction is held from 19h00 to 19h30 in D-1 and covers
hours from 00h00 to 13h59. The second auction is held in D from 08h20 to 08h50 and covers hours
from 14h00 to 23h59.
Bilateral transfers in intraday timeframe have been implemented under the new IFA rules.
d. Balancing exchanges
The development of balancing trades between neighbouring countries is actively supported because
these trades:
-
help to improve security of supply,
-
allow a reduction of the imbalance settlement price by providing the TSO with cheaper
supplies and by increasing competition on the balancing market,
-
constitute a step towards the integration of the balancing mechanisms acknowledged as
th
necessary if the internal market in electricity is to work properly (conclusions of the 13
9
Florence Forum and European Commission Communication of 10 January 2007 ).
Table 8 Organisation of balancing exchanges
Cross-border
procurement of
reserves
Cross-border balancing energy
Model implemented:
Fee to access
TSO-TSO, TSOinterconnection
Provider, regional
capacity
balancing market
Emergency
contract
France – GB
No
TSO-TSO
Yes
Yes
GB – France
No
TSO-TSO
Yes
Yes
GB – Ireland
Yes
TSO-TSO
Yes
Yes
Ireland – GB
Yes
TSO-TSO
Yes
Yes
Source: CER, CRE, Ofgem, NIAUR
Since March 2009, the “interim solution” of the BALIT TSO-TSO balancing model, that improves
reciprocal access to cross border balancing services in England and France, has been implemented.
10
This allows TSOs to exchange six prices per day, compared to only one previously under the BASA
contract.
Regulators are currently reviewing experiences with the Interim solution with the TSOs concerned.
Regulators will also approve the methodology for an appropriate remuneration scheme for use of the
9
COM(2006) 851 final
10
BASA BAlancing Services Agreement is an emergency contract from the French perspective but an TSO-TSO
exchange model from an UK perspective
11
IFA infrastructure for balancing services as soon as they receive required information. It was expected
that an “enduring solution” with more prices and greater automation should be finalised and
implemented in November 2009. However, this has been delayed to November 2010 while a
feasibility study on adding 2 hours balancing products within enduring solution is undertaken by the
TSOs.
On the Moyle Interconnector, NGC are currently putting in place a solution for a more developed form
of SO-SO Trading, potentially allowing, firm trades day ahead for SONI.
12
2. Economic efficiency of congestion management
methods
a. Global figures
Competition indicators
This section compares the actual congestion income (i.e. the auction revenue), which reflects the
market participants’ inclination to pay, with an indicator of the theoretical congestion income, whose
11
calculation is based on ex-post hourly price differentials between the national markets.
Ideally, the actual congestion income should equal the theoretical (ex-post) congestion income. In
reality, that is not generally the case, because of:
-
-
the difficulty the market participants experience with forecasting day-ahead price differentials,
and all the more so, for one month or one year ahead;
the market participants’ preference for trades of longer-term products (such as baseload and
peakload products of a day), along with the difficulty or even impossibility for the market
participants to carry out arbitrage in hourly steps;
economic failures in the interconnected markets (small number of participants, information
asymmetry, size differences).
Thus, the numbers presented in the following tables give an indication about the potential inefficiency
of the congestion management methods.
Moreover, an inter-temporal monitoring of the ratio between the real income revealed by market
mechanisms and this theoretical congestion income could be useful to reveal congestion
management mechanism failures, incompatibility between market designs, or lack of competition at
12
the interconnection.
It could also be used to evaluate the impact of modifications of the interconnection access rules and
changes in national market designs and to assess, whether, and to what extent, the process is
evolving towards the establishment of an internal electricity market.
Table 9 Actual and theoretical congestion rents
Actual congestion
rent or auction
revenues (M€)
France – GB
GB – France
GB – Ireland
Ireland – GB
180,7
24,8
N/A
Ex-post
assessment
of the
congestion
13
rent (M€)
372,4
20,8
N/A
Ratio actual /
ex-post
assessment of
congestion rent
49%
119%
N/A
Source: CER, CRE, Ofgem, NIAUR
11
For the UK, peak and off-peak OTC prices published by Platts are used.
12
The monitoring of this ratio will be more precise if a distinction is made between the different timeframes
according to which the capacities are allocated (see sections 1.b and c).
13
The theoretical congestion income for export from market A to market B is the sum of the whole interconnection
capacity allocated (i.e. all the different timeframes taken together) multiplied by the price differential between the
two markets, for all the hourly steps in the year when the market B price is higher than the market A price.
13
Table 10 Capacity holders and users
France – GB
GB – France
GB – Ireland*
Ireland – GB*
Number of
interconnection
capacity
14
holders
Largest
15
share
Sum of the
three largest
shares
24
23
5
2
19
27
27
75
50
53
70
100
*These are annual figures
Source: CER, CRE, Ofgem, NIAUR
Prices attributed to interconnection capacities
Allocation mechanisms by auction, whether explicit or implicit, mean that the value the market gives to
interconnection capacities can be estimated.
The average hourly price revealed by the auctions for each interconnection MW, for all timeframes, is
16
one way of comparing the various interconnections within the FUI region . Notably, it can be used:
- within the perspective of investment in new interconnection lines; as an indication, the cost of
constructing an alternative current interconnection line is 300 to 500k€/MW, and 600k€ to
17
800k€/MW for direct current ;
- to improve the method used by TSOs for sharing export capacity on their borders
Table 11 Prices attributed to interconnection capacities
Average prices
€/MWh
€/MW
France – GB
10,41
GB – France
1,45
GB – Ireland
8,50
Ireland – GB
1,16
Note: annual average rate GBP-euro used : 1.26
91 484
12 767
74,50
10.16
Total
€/MW
104251
84,66
Source: CER, CRE, Ofgem, NIAUR
Congestion level
In order to investigate whether the interconnection is used in an efficient (i.e. coherent with the
economic signal given by the price difference) way, it is useful to assess whether the net flow on the
interconnector is coherent with the price spread. In addition, an indication is given about the level of
use of the interconnector when the former condition is met. The first two columns of the following
indicate when the use of the interconnection is coherent with a significant price differential and the
level of utilisation of the interconnection capacity (partial utilisation versus maximum utilisation).
Theoretically, in such a case, the interconnection should be used at the maximum. Potential reasons
why that may be not the case are: lack of transparency, flexibility, the forecast errors of traders. The
14
This figure is the number of user companies whatever the relationship between them (for example :
subsidiaries)
15
The largest share corresponds to the largest percentage of nominated capacities made by one user all
products taken together.
16
The figures in the following table take into account all the revenues and all the allocated capacities at the
different timeframes.
17
Estimations based on the most recent constructions. The total cost of interconnection infrastructure is likely to
vary widely according to the length of the link, scale of the associated work (construction work on stations,
upgrading of national links, dismantling of existing links, etc.), the nature of the environment (plains, mountains,
etc.), and adaptation to planning constraints (landscaped pylons, burial, modification of the route, etc.). In
addition, the commercial capacity available may be less than the technical capability of the link and fluctuates
according to the change in flows on the grid.
14
last column of the following table indicates when the use of the interconnection (net scheduled flow) is
not coherent with the economic signal given by the price differential.
Table 12 Consistency of cross-border flows and price differentials
Interconnection between
France & GB
Ireland & GB
Percentage of time when the net scheduled flow
is coherent with a significant price differential and
18
capacity is:
not used at the
maximum
47%
Percentage of time
when the net scheduled
19
flow is not coherent
with the price
differential
used at the maximum
39%
10%
Imports- 75%,
exports - 60%
Note -on Moyle IC only
25% of the variation in
daily average imports
can be explained by
the variation in the
daily average price
differential over period
01/11/07 – 31/12/08
40% of the variation in
exports can be
explained by variations
in the price differential
20
for this period
18
A price spread is assumed to be significant in this respect if it is greater or equal to a positive price spread of
1€/MWh. Moreover, the capacity taken into account for the computation corresponds to the nominated capacities
of the sum of all products taken together.
19
The net scheduled flow is the difference between the nominations made in both directions; reductions or
curtailments are taken into account.
20
In the absence of a day- ahead price and power exchange in the SEM, it is not at present possible to calculate
this for the SEM – GB. The SEM is a gross mandatory pool with day ahead gate clsoure in which bids are
optimised over the whole day with an ex-post single market clearing price that is calculated 4 days after the
trading day.
15
b. Long and medium term capacities
On all the interconnections within the FUI region, capacities are allocated on several different
timeframes. The long-term products on offer are generally as follows:
-
long term capacity: a capacity band allocated for the whole of the next year (calendar year
and business year are allocated;
-
medium term capacity: a capacity band is allocated for the next month, quarter or season
(monthly quarterly or seasonal auctions);
Holding long-term capacities is one of the main methods for market operators to gain a lasting position
on a foreign market. In this regard, improving the quality of the products offered by the TSOs and
maximising interconnection capacities are important challenges for developing competition and
constructing the European electricity market.
As for any commodity, the price that the market operators are willing to pay to obtain this commodity
depends on the intrinsic characteristics of the product sold: the more reliable the product sold is
(firmness, compensation in the event of curtailment, etc.) and easy-to-use (existence of a secondary
market, nomination procedure, financial/physical nature, etc.), the more valuable it is.
Market operators wishing to participate in long-term auctions can consider two price references in
order to determine their willingness to pay for the capacity. On the one hand, if they are involved in
long-term arbitrages, they can consider the price differential of forward products available on the day
of the auction. On the other hand, if they are interested in shorter-term arbitrages, this initial value has
to be supplemented by their estimate, for the period in question, of price differential volatility on an
hourly, (or daily, weekly, etc.) basis.
As National regulatory Authorities usually does not have access to these estimates, which differ for
every market operator, this report considers the theoretical value of capacities, calculated ex-post,
based on volatility of hourly price differentials. When the operators’ forecasts do not materialise,
typically in the case of unexpected weather conditions (heat wave, very cold spell, etc), this value may
be lower than the weighted average auction price. With this exception, the weighted average price
revealed by annual (or monthly) auctions must, in principle, be:
-
at least the same order of magnitude as the price differential of annual (or monthly)
forward products, observed on the date the auction is held;
-
lower than the theoretical capacity value, calculated ex-post based on the hourly price
21
differential between the organised markets throughout the year (or month) .
21
The theoretical value of the annual (or monthly) export capacity from market A to market B is the average of the
price differential between the two markets over all the hourly steps in the year (or month) during which the market
B price is higher than the market A price.
16
Table 13 Competition indicators for long term auctions
Capacity sold
(MW)
Number of
participant
22
s to the
auction
Number
of
capacity
holders
17
12
France – GB
900
GB – France
900
17
11
GB – Ireland
Ireland – GB
257
18
5
2
5
2
Ex-post
Weighte
Ratio actual /
Forward
assessme
d
ex-post
price
nt of the
average
assessment
differential
congestio
price
of congestion
23
n rent
(€/MWh)
(€/MWh)
rent
24
(€/MWh)
(*)
7,10
21,52
33%
(*)
1,86
1,21
154%
N/A
N/A
N/A
Profit of
participants
realizing
perfect
arbitrages
25
(€/MWh)
14,42
-0,65
N/A
Source: CER, CRE, Ofgem, NIAUR
(*) Lack of the same reference between UK and France to define the forward price differential
Table 14 Competition indicators for medium term auctions
France – GB
GB – France
GB – Ireland
Ireland – GB
Average
capacity
sold (MW)
Average
number of
participan
ts to the
auctions
Average
number of
capacity
26
holders
Weighted
average
price
(€/MWh)
900
900
61
31
26
26
2
2
24
22
1
2
13,07
1,21
Ratio
actual /
ex-post
assessme
nt of
congestio
n rent
91%
398%
Profit of
participants
realizing
perfect
arbitrages
27
(€/MWh)
4,85
0,06
Source: CER, CRE, Ofgem, NIAUR
22
This figure is the number of participating companies whatever the relationship between them (for example :
subsidiaries)
23
The price differential is the one observed on the auction day and computed based on the results of the power
exchanges or, if there is no such possibility, on the estimates based upon OTC trades. Given that OTC trades
make up a large proportion of trades in the GB market, the price differential may be over-stated.
24
The theoretical value of the capacity for export from market A to market B is the sum of the interconnection
capacity multiplied by the price differential between the two markets, for all the hourly steps in the year when the
market B price is higher than the market A price.
25
This figure corresponds to the maximum profit that an actor that bought the same capacity every month could
have earned. The average profit of participants realizing perfect arbitrages is the hourly average of the difference
between
the differential spot price if positive, zero otherwise
- and the weighted average prices of the monthly capacities.
26
This figure is the number of user companies whatever the relationship between them (for example :
subsidiaries)
27
This figure corresponds to the maximum profit that an actor that bought the same capacity every month could
have earned. The average profit of participants realizing perfect arbitrages is the hourly average of the difference
between
the differential spot price if positive, zero otherwise
- and the weighted average prices of the monthly capacities.
17
Secondary markets
On some borders, there are secondary capacity markets, which enable the holders of long-term
capacities to sell on or transfer their products.
Two mechanisms coexist:
-
resale of capacities: long-term capacities can be sold on at daily auctions (at hourly time
intervals), at the request of holders of capacities at least 2 days before day D (the original holder
of the capacity then receives the daily auction price); similarly, annual capacities can be sold on in
the form of a band, at monthly auctions;
-
transfer of capacities (or reassignments): the operators can trade long-term capacities bilaterally
over a period of their choice (hourly time intervals).
Table 15 Resale of annual capacities to monthly auctions
number of
operators
using this
service
France – GB
GB – France
GB – Ireland
Ireland – GB
0
0
N/A
N/A
proportion of
operators using this
service compared
with the number of
holders of long-term
capacities
0
0
N/A
N/A
average
capacity
resold (MW)
average
share of
long-term
capacities
0
0
0
0
N/A
N/A
N/A
N/A
Source: CER, CRE, Ofgem, NIAUR
Table 16 Resale of long and medium term capacities to daily auctions
number of
operators
using this
service
France – GB
GB – France
GB – Ireland
Ireland – GB
1
2
N/A
N/A
proportion of
operators using this
service compared
with the number of
holders of long-term
capacities
3%
6%
N/A
N/A
average
capacity
resold (MW)
average
share of
long-term
capacities
50
3%
76
4%
N/A
N/A
N/A
N/A
Source: CER, CRE, Ofgem, NIAUR
Table 17 Bilateral transfers of long and medium term capacities
number of
operators
using this
service
France – GB
GB – France
GB – Ireland
Ireland – GB
0
0
1
0
proportion of
operators using this
service compared
with the number of
holders of long-term
capacities
0
0
20%
0
average
capacity
transferred
(MW)
average
share of
long-term
capacities
0
0
0
0
42
15
0
0
Source: CER, CRE, Ofgem, NIAUR
18
The previous tables allow regulators to analyse the secondary market use and its importance. This
enables us to see whether the actors really need those services and/or whether there exists difficulties
in the use of those services.
Although the secondary market for the IFA interconnection is free of charge for users, very few
operators used this mechanism in 2008.
The secondary market as it existed in 2008 on IFA interconnection allows the operators to resell or
transfer to one another only 24-hour capacity bands (in accordance with the products sold on the
primary capacities market). The lack of flexibility of the product, because of the impossibility of
transferring or reselling capacities in hourly intervals, could explain why there was little interest among
the operators in the resale mechanism on this interconnection.
c. Day-ahead capacities
The value of the daily capacities, hour by hour, should be viewed in relation to the hourly price
differential between the markets.
In reality, because the daily explicit auctions take place before the prices are fixed on the organised
markets, those taking part in the auctions can only use estimates of the price differential, and this
could partially explain the difference between the auction result and the price differential. This is one
characteristic of the separation of the energy and transmission markets (allocation by explicit
auctions).
Table 18 Competition indicators
Average
capacity
sold (MW)
France – GB
GB – France
GB – Ireland
Ireland – GB
149
122
N/A
Average
number of
28
participants to
the auctions
N/A
Average
number of
capacity
29
holders
2
2
N/A
Profit of participants
realizing perfect
30
arbitrages (€/MWh)
6,73
0,81
N/A
Source: CER, CRE, Ofgem, NIAUR
Consistency of nominations with price differentials
The following table should be read as follows:
-
the first column gives the annual average for nominations in the opposite direction to the
price differential;
-
the second column, for the number of hours when the price differential was in a particular
direction, gives the ratio of the number of hours during which the nominations were in the
opposite direction;
28
This figure is the number of participating companies whatever the relationship between them (e.g.
subsidiaries).
29
This figure is the number of user companies whatever the relationship between them (e.g. subsidiaries).
30
This figure corresponds to the maximum profit that an actor that bought the same capacity every day could
have earned. The average profit of participants realizing perfect arbitrages is the hourly average of the difference
between
the differential spot price if positive, zero otherwise,
- and the weighted average price of the daily capacities.
19
-
the third column gives the annual average capacity not nominated in the direction of the
price differential;
-
finally, the fourth column gives the number of hours during which the capacity was not
fully nominated in a particular direction divided by the number of hours during which the
price differential was in the same direction.
Ideal use of daily capacities would correspond for each hour in the year to:
-
maximum use in the direction of the price differential: the rate of use of these capacities
(nominated capacities divided by available capacities) should be equal to 1;
-
no use in the opposite direction to the price differential: the rate of use should then be
zero.
So the ideal use of capacities described above would therefore produce all zeros in the four last
columns.
Table 19 Consistency of nominations with price differentials
Average capacity
used in the opposite
direction to the price
differential (MW)
653
288
N/A
N/A
France – GB
GB – France
GB – Ireland
Ireland – GB
Proportion
of hours
concerned
75%
16%
N/A
N/A
Average capacity
Proportion
not used in the
of hours
price differential
concerned
direction (MW)
402
98%
1559
100%
N/A
N/A
N/A
N/A
Source: CER, CRE, Ofgem, NIAUR
Table 20 Simultaneous nominations in both directions
IFA
MOYLE
Number of concerned
actors
11
Number of
hours
3120
0
0
Average concerned
capacity (MW)
68
0
Source: CER, CRE, Ofgem, NIAUR
Table 21 Estimate of the loss associated with the absence of netting between long-term
capacity nomination and day-ahead allocation
The netting of long-term capacities allows for long-term capacity nominated in the opposite direction to
be reallocated at the daily auctions. Netting is a requirement of Regulation (EC) No 1228/2003.
Loss due to the
absence of
netting (M€)
France – GB
GB – France
Netting not
applied
GB – Ireland
Ireland – GB
N/A
N/A
Total
Total
N/A
N/A
N/A
Source: CER, CRE, Ofgem, NIAUR
20
Table 22 Day-ahead price convergence
% of time where daily
price differential is
lower than 1 €/MWh
3%
N/A
Source: CER, CRE, Ofgem, NIAUR
France & GB
Ireland & GB
Table 23 Estimate of the “loss in social welfare” associated with the absence of implicit
methods
31
The “loss in social welfare” associated with the absence of market coupling between two borders is
estimated as follows: for each hour, it is the product of the positive part of the price differential
between the exchanges and the daily capacity that remains unused or is used in the opposite
direction. This estimate should be considered with caution (see the inset below). However, it does at
least give an idea of the scale of this loss of social welfare on each border.
Within the region
France – GB
GB – France
GB – Ireland
Ireland – GB
Loss in social
welfare (M€)
Total (M€)
50,12
24,88
75,01
N/A
Total
N/A
75,01
Source: CER, CRE, Ofgem, NIAUR
Inset – Limitations of this estimate
• The estimate assumes “all else being equal” and in particular it does not take account of the possible
change in behaviour of the market operators in the organised markets following the introduction of
market coupling. It is difficult to make an ex ante assessment of the impact of introducing market
coupling on the buying and selling offer strategies of market operators in the organised markets.
• The estimate does not take account of market resilience, i.e. the impact on prices of altering the
volumes exchanged. Better use of daily capacities would lead to price convergence; the figures given
in Table 13 are therefore the upper bounds of actual loss of social welfare, which can only be
estimated precisely using aggregated curves of supply and demand on each market.
d. Intraday capacities
Access to cross-border intraday trades offers operators greater flexibility for balancing their position
when coping with an unexpected event, and also enables them to engage in short-term arbitrages.
In 2008, no intraday mechanism was in place in the FUI region.
31
Or loss of collective surplus.
21
e. Balancing exchanges
Cross-border balancing reserves
First indicators for the balancing cross border exchanges are whether it is possible at all to contract
generation capacities abroad and the share it represents. Regarding the possibility of contracting
balancing reserves abroad this depends firstly on the permission and secondly on technical or
organisational feasibility according to the relevant national balancing and/or scheduling regimes.
Reasons why this is not allowed or technically limited may be further investigated by regulators.
Table 24 Cross-border balancing reserves
Share of (secondary and tertiary) reserves contracted abroad (%)
0%
0%
0%
Source: NG, RTE, SONI
France
GB
Ireland
Table 25 Exchange of balancing energy
The following table gives information on the flows that occurred both in normal and emergency
situations. The objective is to see to what extent actors or TSOs are active.
In 2008, flows are all under the BASA contract. BASA allows TSOs to exchange one price per day.
These flows are explained by the fact this contract is not used to the same extent, RTE use BASA as
an emergency contract but NG use BASA as TSO-TSO exchange model.
32
France – GB
33
GB – France
GB – Ireland
Ireland – GB
Cross-border balancing
Upward
Downward
balancing
balancing
energy (GWh) energy (GWh)
235.5
0
0
61.7
N/A
N/A
N/A
N/A
Emergency contracts
Upward
Downward
balancing
balancing
energy (GWh) energy (GWh)
0.05
0
0
1.18
N/A
N/A
N/A
N/A
Source: NG, RTE, SONI
Table 26 Cross-border competition
As shown in table 25, the amount of energy exchanged between France and GB is very small.
Nonetheless, due to the size of the balancing markets, foreign market players, and in particular
German and Swiss market players, represent a non-negligible source of competition within the French
balancing markets.
France
GB
Ireland
Market share of FUI foreign market
participants (upward balancing energy)
13%
0%
N/A
Market share of FUI foreign market
participants (downward balancing energy)
12%
0%
N/A
Source: NG, RTE, SONI
32
As an upward offer is a flow to the country activating the offers and downward offer is a flow from the country
activating the offers, these figures refer to UK TSO’s activation of French upward offers and RTE’s emergency
activation of UK downward offers.
33
These figures refer to RTE’s emergency activation of UK upward offers and UK TSO’s activation of French
downward offers.
22
Table 27 Unused interconnection capacity after intraday trade gate closure
The following table gives information on the theoretically available capacity for cross-border balancing
exchanges. It allows assessing whether there are considerable opportunities left.
The available capacity is the average of daily NTCs netted by all previous exchanges (long term to
day ahead). The second column indicates the percentage of hours when this remaining capacity is
higher than 100 MW.
France – GB
GB – France
GB – Ireland
34
Ireland – GB
Average available
capacity
580
2916
Percentage of time when available
capacity is over 100 MW
35%
100%
371
98
Source: NG, RTE, SONI
Table 27 shows that interconnection capacity available for balancing exchanges is not an impediment
for developing cross-border balancing. Indeed, the available capacity unused after intraday gate
closure is on average very significant and most of the time, depending on the interconnection, higher
than 100 MW. Furthermore, it should be reminded that balancing needs and prices are not always
correlated with day-ahead / intraday trades. Therefore, even if interconnection capacity was saturated
on one direction, balancing exchanges could still be possible and valuable on the other direction.
Table 28 Estimate of inefficiencies
Table 28 details the information given in the previous table in computing the available capacities when
the price signal is positive but low and positive and high. This allows us to better appreciate the
potential to develop the cross-border exchanges.
36
France – GB
37
GB – France
GB – Ireland
Ireland – GB
Percentage of time when
interconnection capacity available
35
is over 100 MW and difference
between upward balancing prices
is over 2 €/MWh
26%
33%
N/A
Percentage of time when
interconnection capacity available
is over 100 MW and difference
between upward balancing prices
is over 50 €/MWh
16%
5%
N/A
Source: NG, RTE, SONI
34
During 2008 flows on the Moyle were low, from July to Oct the net flow on the interconnector was export from
SEM. This current situation (August 09) is all capacity has been sold (410MW) and is being used. The connection
agreement from Ireland to GB is 80MW, restricting exports to this level
35
Due to the unavailability of UK marginal prices, these balancing prices differences are calculated by the
difference between UK imbalance settlement prices (500MWh marginal) and French weighted average price.
36
UK TSOs could have activated French upward balancing offers at a better cost
37
RTE could have activated UK upward balancing offers at a better cost
23
38
France – GB
39
GB – France
GB – Ireland
Ireland – GB
Percentage of time when
interconnection capacity available
is over 100 MW and difference
between downward balancing
prices is over 2 €/MWh
24%
33%
N/A
Percentage of time when
interconnection capacity available
is over 100 MW and difference
between downward balancing
prices is over 50 €/MWh
4%
2%
N/A
Source: NG, RTE, SONI
38
As for downward regulation, electricity flow and merit order are reversed, this row means that RTE could have
activated UK downward balancing offers at a better cost
39
UK TSOs could have activated French downward balancing offers at a better cost
24
3. Capacity calculation and management of cross-border
flows
The question of capacity levels is a very difficult one, and a major challenge for the development of
the European energy market.
The challenge in the short term is to optimise the use of existing infrastructure by making available to
the market operators “the maximum capacity of the interconnections and/or the transmission networks
affecting cross-border flows […], complying with safety standards of secure network operation” (Article
6(3) of Regulation (EC) No 1228/2003). On direct current interconnections such as the interconnector
between GB and France, the full amount of capacity is offered to the market irrespective of
transmission system conditions. If there is an equipment outage the maximum capacity less this
amount will be made available however DC capability is not a function of the AC systems to which it is
connected.
In the longer term the challenge is to develop new transmission infrastructure. For regulated
interconnector investment this requires coordination by the TSOs to identify investment needs,
authorisation from relevant bodies to build the new lines and coordination how the investment should
be financed. For merchant investment, exemptions must be sought and approved by the Commission
for the investment to go ahead.
a. Principles of the capacity calculation method by TSOs
General capacity calculation procedure
In the SEM, the Interconnector owner calculates the Available Transfer Capacity for each half hourly
trading period in the trading day and this is published by 10.00am on D-2.
25
Table 29 Application of Use-It-Or-Lose-It and netting
As a reminding, the so called “Use It Or Lose It” principle implies that long-term rights are lost if they
are not nominated40 and the netting of long-term capacities allows for long-term capacity nominated in
41
the opposite direction to be reallocated at the daily auctions .
Between long term
capacity nomination and
day-ahead allocation
Between dayahead capacity
nomination and
intraday allocation
UIOLI
Netting
UIOLI
Netting
NO
NO
NO
NO
NO
NO
France – GB
GB – France
GB – Ireland
Ireland – GB
Between intraday
allocation and
nomination
UIOLI
Netting
NO
NO
NO
NO
NO
NO
Source: NG, RTE, SONI
b. Net transfer capacity
Evolution of the net transfer capacity
The data given in the following table give insights about the way the NTC computed two days before
the delivery day evolves compared to the previous years.
The average permits to judge whether the capacity increase or decrease.
The first and last deciles permit to understand whether the daily NTC evolve in a range close to the
average and whether the average is close to one of those two thresholds.
Table 30 Evolution of the net transfer capacity over time
2008
France – GB
GB – France
GB – Ireland
Ireland – GB
2007
2006
Average
NTC
First
decile
Last
decile
Average
NTC
First
decile
Last
decile
1912
1584
450(
winter) /
410
Summer
80 mw
1500
0
2000
2000
1881
1805
450(
winter) /
410
Summer
80 mw
1500
1500
2000
2000
Average
NTC
First
decile
1835
1500
1821
1500
450(
winter) /
410
Summer
80 mw
Source: NG, RTE, SONI
40
In order to check whether the UIOLI is applied, the capacity offered at the sub timeframe (for example, day
ahead) must take into account the capacity not nominated at the upper timeframe (for example, year ahead)
Example: 50 MW sold in the year ahead auction and only 30 MW are nominated at a particular day: the day
ahead auction for that particular day must .offer the ATC computed plus the 20 MW non nominated.
The UIOLI is cumulative with the netting.
41
In order to check whether the netting is applied, the capacity offered in a direction in the sub time frame (for
example, day ahead) must take into account the capacity nominated in the opposite direction in the upper time
frame (for example, year ahead)
Example: 50 MW of the year ahead capacities are nominated from A to B for a particular day. In the day ahead
auction for that particular day, the capacity offered from B to A must offer the ATC computed plus the 50 MW
nominated in the other direction.
The netting is cumulative with the UIOLI.
26
Last
decile
2000
2000
The previous comparison enables to know whether the net transfer capacity is stable for a year to
another and whether within a year the net transfer capacity varies in an important way. This allows us
to appreciate the difficulty for TSOs to allocate a high level of long-term capacities.
Comparison between the NTC and the offers made at the long and medium capacity auctions
The indicators computed in the following table are designed to give insights about the risk taken by
TSOs in order to optimize the level of long- and medium-term capacities.
The second and third columns enable us to see whether TSOs took actions in order to maintain the
level of the allocated capacities and its level and whether reductions occurred and the duration over
the year.
The fourth and fifth columns allow comparing the yearly capacity allocated to the capacity that would
have been allocated if specific measures (such as curtailments, counter-trading, buy back strategy by
TSOs…) were applied less than 1% of the time in one month (about 8 hours in only one month).
The sixth and seventh columns allow comparing the yearly and monthly capacities allocated along the
year to the average capacity that would have been allocated if specific measures were applied less
than 1 % of the time in every month (about 8 hours every month).
Table 31 Comparison between the NTC and the offers made at the long and medium capacity
auctions
Average of
Number of
Minimum
Number of
the sum of
Average
hours
Yearly
first
the yearly
hours
first
where
percentile
capacity
where
and
percentile
counter–
offered
observed
reductions
monthly
observed
trading
(MW)
for one
occurred
capacities
monthly
occurred
month
offered
France – GB
N/A
900
1800
1800
1867
GB – France
900
1764
1800
1805
GB – Ireland
N/A
N/A
N/A
N/A
N/A
N/A
Ireland – GB
*Non available
Source: NG, RTE, SONI
Remark: Those figures enable to know the importance of countertrading actions undertaken by TSOs
to guarantee the firmness of allocated capacities or nominations, as well as the occurrence of the
reductions. They also enable to compare the offered capacities (yearly and monthly) to the level of
capacity that could be made available with a small and arbitrary level of redispatching. Nevertheless, it
should be highlighted that to be able to correctly assess to which extent TSOs are maximizing or not
the level of long and medium capacities, further information would be needed regarding the cost of
additional redispatching actions.
c. Costs for ensuring the compatibility of the cross-border
flows with grid security
TSOs operating AC interconnectors regularly have to deal with situations where not all the long-term
capacities they have allocated can be physically used, because that would jeopardise the safety of the
grid. Five tools are potentially available for them to cope with these constraints are described below
however they are not always applicable or available for TSOs operating DC interconnectors:
-
Repurchase of capacities by the TSOs: the TSOs could participate in the secondary market
like any other operators, enabling them to buy back the “excess” capacity allocated to the
market operators. For the TSOs this means outsourcing the management service of the
secondary market, which has to be provided in the form of an anonymous organised market.
At present this facility is not available to the TSOs.
-
Curtailment of the allocated capacities: subject to payment of compensation, holders of longterm capacities can have some of their transfer rights reduced. On the IFA long term rights
27
are not curtailed to maintain transmission system security, IFA curtailment only occurs where
there is a capability reduction resulting from DC equipment failure.
-
Countertrading by the TSOs on D-1: the TSOs could use existing allocation mechanisms to
trade in the opposite direction to the price differential, to remove the constraint. This would be
particularly easy in a market-coupling situation because it is the TSOs who convey the trades,
but this procedure is not used at present.
-
Redispatching: the TSOs can activate offers through the balancing mechanisms on both sides
of the border, to lift the constraints.
-
Changing the topology of the grid: the TSOs can use phase-shifting transformers installed on
certain lines to redirect flows on the grid in real time. It should be noted that this function isn’t
available to DC interconnector operators.
Not all these tools are equivalent or as effective as one another for dealing with the constraints.
Repurchasing capacity and reducing capacity only work if the decision to do so is made far enough in
advance – and in any case before the long-term capacities are nominated – as a preventive measure
that helps to guarantee the safety of the grid. To the extent that they can only have an indirect impact
on the physical flows, without any guarantee that the change this causes to the physical flows will
actually lift the constraint, these tools cannot in any way be seen as last-resort curative solutions to
guarantee the safety of the grid.
On the other hand, since they have a direct impact on the physical flows and on the constraints,
redispatching and changing the topology of the grid are the only effective curative actions to
guarantee the safety of the grid approaching real time.
All these tools have a cost for the TSOs: for example, installing phase-shifting transformers to change
the grid topology amounts to a substantial fixed cost. Redispatching also has a cost, which is that of
the offers activated in the balancing mechanism. These offers have to be activated in increasing price
order so that, in accordance with point 1.3 of the new guidelines for Regulation (EC) No 1228/2003,
the action taken by the TSOs is economically efficient.
Table 32 Costs of ensuring compatibility of cross-border flows with grid security
Redispatching and
counter-trading costs
(M€)
France – GB
GB – France
GB – Ireland
Ireland – GB
N/A
Compensation for
curtailments (k€)
No compensation
N/A
Compensation for
auction
cancellations
No compensation
N/A
Capacity buying
42
back costs
no formal buy back
mechanism in FUI
N/A
N/A
Source: NG, RTE, SONI
d. Curtailments occurred in 2008
Table 33 Capacity curtailments
France – GB
GB – France
GB – Ireland
Ireland – GB
Number of
curtailments
207
1780
1
1
Average
duration (h)
41
61
2
2
Number of
impacted days
96
12
1
1
Average capacity
curtailed (MW)
689
591
0
75
Source: NG, RTE, SONI
42
During 2008, the GB TSO bought long term capacity back from IFA users on a few occasions at a cost of
£130,000.
28