Europaudvalget 2016
KOM (2016) 0864
Offentligt
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EUROPEAN
COMMISSION
Brussels, 30.11.2016
SWD(2016) 410 final
PART 3/5
COMMISSION STAFF WORKING DOCUMENT
IMPACT ASSESSMENT
Accompanying the document
Proposal for a Directive of the European Parliament and of the Council on common
rules for the internal market in electricity (recast)
Proposal for a Regulation of the European Parliament and of the Council on the
electricity market (recast)
Proposal for a Regulation of the European Parliament and of the Council establishing
a European Union Agency for the Cooperation of Energy Regulators (recast)
Proposal for a Regulation of the European Parliament and of the Council on risk
preparedness in the electricity sector
{COM(2016) 861 final}
{SWD(2016) 411 final}
{SWD(2016) 412 final}
{SWD(2016) 413 final}
EN
EN
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TABLE OF CONTENTS
1. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA I, OPTION 1(A):
LEVEL PLAYING FIELD AMONGST PARTICIPANTS AND RESOURCES ......................4
1.1. Priority access and dispatch .............................................................................................................. 4
Summary table ................................................................................................................................. 4
Description of the baseline .............................................................................................................. 5
Deficiencies of the current legislation ............................................................................................. 6
Presentation of the options ............................................................................................................. 9
Comparison of the options ............................................................................................................ 11
Subsidiarity ..................................................................................................................................... 14
Stakeholders' opinions ................................................................................................................... 14
1.2. Regulatory exemptions from balancing responsibility ..................................................................... 17
Summary table ............................................................................................................................... 18
Description of the baseline ............................................................................................................ 19
Deficiencies of the current legislation ........................................................................................... 20
Presentation of the options ........................................................................................................... 22
Comparison of the options ............................................................................................................ 24
Subsidiarity ..................................................................................................................................... 25
Stakeholders' opinions ................................................................................................................... 26
1.3. RES E access to provision of non-frequency ancillary services ......................................................... 29
Summary table ............................................................................................................................... 30
Description of the baseline ............................................................................................................ 31
Deficiencies of the current legislation ........................................................................................... 33
Presentation of the options ........................................................................................................... 34
Comparison of the options ............................................................................................................ 35
Subsidiarity ..................................................................................................................................... 36
Stakeholders' opinions ................................................................................................................... 37
2. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA I, OPTION 1(B)
STRENGTHENING SHORT-TERM MARKETS .................................................................. 39
2.1. Reserves sizing and procurement .................................................................................................... 41
Summary table ............................................................................................................................... 42
Description of the baseline ............................................................................................................ 43
Deficiencies of the current legislation (see also Section 7.4.2 of the evaluation) ......................... 47
Presentation of the options ........................................................................................................... 48
Comparison of the options ............................................................................................................ 49
Subsidiarity ..................................................................................................................................... 50
Stakeholders' opinions ................................................................................................................... 50
2.2. Removing distortions for liquid short-term markets ....................................................................... 53
Summary table ............................................................................................................................... 54
Description of the baseline ............................................................................................................ 55
Deficiencies of the current legislation ........................................................................................... 58
Presentation of the options ........................................................................................................... 59
Comparison of the options ............................................................................................................ 60
Subsidiarity ..................................................................................................................................... 62
Stakeholders' opinions ................................................................................................................... 63
2.3. Improving the coordination of Transmission System Operation ...................................................... 65
Summary table ............................................................................................................................... 66
2
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Detailed description of the baseline .............................................................................................. 67
Deficiencies of the current legislation ........................................................................................... 70
Presentation of the options ........................................................................................................... 72
Comparison of the options ............................................................................................................ 76
Subsidiarity ..................................................................................................................................... 88
Stakeholders' opinions ................................................................................................................... 89
3. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA I, OPTION 1(C);
PULLING DEMAND RESPONSE AND DISTRIBUTED RESOURCES INTO THE
MARKET .................................................................................................................................... 90
3.1. Unlocking demand side response .................................................................................................... 92
Summary table ............................................................................................................................... 93
Description of the baseline ............................................................................................................ 94
3.1.2.1. Smart Metering ...................................................................................................................... 94
3.1.2.2. Market arrangements for demand response ......................................................................... 96
Deficiencies of current legislation ................................................................................................ 102
3.1.3.1. Deficiencies of current Smart Metering Legislation ............................................................. 102
3.1.3.2. Deficiencies of current regulation on demand response ..................................................... 103
Presentation of the options ......................................................................................................... 104
Comparison of the options .......................................................................................................... 107
Subsidiarity ................................................................................................................................... 126
Stakeholders' opinions ................................................................................................................. 130
3.2. Distribution networks ................................................................................................................... 143
Summary table ............................................................................................................................. 144
Description of the baseline .......................................................................................................... 145
Deficiencies of current legislation ................................................................................................ 150
Presentation of the options ......................................................................................................... 152
Comparison of the options .......................................................................................................... 152
Subsidiarity ................................................................................................................................... 156
Stakeholders' opinions ................................................................................................................. 157
3.3. Distribution network tariffs and DSO remuneration...................................................................... 160
Summary table ............................................................................................................................. 161
Description of the baseline .......................................................................................................... 163
Deficiencies of the current legislation ......................................................................................... 167
Presentation of the options ......................................................................................................... 168
Comparison of the options .......................................................................................................... 169
Subsidiarity ................................................................................................................................... 171
Stakeholders' opinions ................................................................................................................. 172
3.4. Improving the institutional framework ......................................................................................... 177
Summary Table ............................................................................................................................ 178
Description of the baseline .......................................................................................................... 179
Deficiencies of the current legislation ......................................................................................... 183
Presentation of the options ......................................................................................................... 187
Comparison of the options .......................................................................................................... 194
Budgetary implications of improved ACER staffing ..................................................................... 197
Subsidiarity ................................................................................................................................... 199
Stakeholders' opinions ................................................................................................................. 200
3
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1. D
ETAILED MEASURES ASSESSED UNDER
P
ROBLEM
A
REA
I,
OPTION
1(
A
):
LEVEL PLAYING FIELD AMONGST PARTICIPANTS AND RESOURCES
1.1. Priority access and dispatch
Summary table
Objective:
To ensure that all technologies can compete on an equal footing, eliminating provisions which create market distortions unless clear necessity is demonstrated, thus ensuring that
the most efficient option for meeting the policy objectives is found. Dispatch should be based on the most economically efficient solution which respects policy objectives.
Option 0
Option 1
Option 2
Option 3
Do nothing.
Abolish priority dispatch and priority Priority dispatch and/or priority access only for emerging Abolish priority dispatch and introduce clear
This would maintain access
technologies and/or for very small plants:
curtailment and re-dispatch rules to replace
rules allowing priority This option would generally require full This option would entail maintaining priority dispatch priority access.
dispatch and priority merit order dispatch for all technologies, and/or priority access only for small plants or emerging This option can be combined with Option 2,
access
for
RES, including RES E, indigenous fuels such as technologies. This could be limited to emerging RES E maintaining priority dispatch/access only for
indigenous fuels and coal, and CHP. It would ensure optimum technologies, or also include emerging conventional emerging technologies and/or for very small
plants
CHP.
use of the available network in case of technologies, such as CCS or very small CHP.
network congestion.
Lowest
political Efficient use of resources, clearly Certain emerging technologies require a minimum number As Option 1, but also resolves other causes for
resistance
distinguishes
market-based
use
of of running hours to gather experiences. Certain small lack of market transparency and discrimination
capacities and potentially subsidy-based generators are currently not active on the wholesale market. potential. It also addresses concerns that
installation of capacities, making subsidies In some cases, abolishing priority dispatch could thus bring abolishing priority dispatch and priority access
transparent.
significant challenges for implementation. Maintaining also could result in negative discrimination for
priority access for these generators further facilitates their renewable technologies.
operation.
Politically, it may be criticized that Same as Option 1, but with less concerns about blocking Legal clarity to ensure full compensation and
subsidized resources are not always used if potential for trying out technological developments and non-discriminatory curtailment may be
there are lower operating cost alternatives. creating administrative effort for small installations. challenging to
establish.
Unless
full
Adds uncertainty to the expected revenue Especially as regards small installations, this could however compensation and non-discrimination is
stream, particularly for high variable cost result in significant loss of market efficiency if large shares ensured, priority grid access may remain
generation.
of consumption were to be covered by small installations.
necessary also after the abolishment of priority
dispatch.
Most suitable option(s): Option 3.
Abolishing priority dispatch and access exposes generators to market signals from which they have so far been shielded, and requires all generators to
actively participate in the market. This requires clear and transparent rules for their market participation, in order to limit increases in capital costs and ensure a level playing field. This should
be combined with Option 2: while aggregation can reduce administrative efforts related thereto, it is currently not yet sufficently developed to ensure also very small generators and/or emerging
technologies could be active on a fully level playing field; they should thus be able to benefit from continuing exemptions.
Cons
Pros
Description
4
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Description of the baseline
Dispatch rules determine which power generation facilities shall generate power at which
time of the day. In principle, this is based on the so-called merit order, which means that
those power plants which for a given time period require the lowest payment to generate
electricity are called upon to generate electricity. This is determined by the day-ahead and
intraday markets. In most Member States, dispatch is then first decided by market results
and, where system stability requires intervention, corrected by the TSO (so-called self-
dispatch systems). In some Member States (e.g. Poland) the TSO integrates both steps,
directly determining on the basis of the system capabilities and market offers made which
offers can be accepted (so-called central dispatch).
Access rules determine which generator gets, in case of congestion on a particular grid
element, access to the electricity network. They thus do not relate to the initial network
connection, but to the allocation of capacity in situations where the network is unable to
fully accommodate the market result. Priority access can thus mean that in situations of
congestion, instead of applying the most efficient way of remedying a particular network
issue, the transmission system operator has to opt for less efficient, more complex and/or
more costly options, to maintain full generation from the priority power plant.
Currently, several Directives allow the possibility or even set the obligation for Member
States to include priority dispatch and priority grid access of certain technologies in their
national legislation:
-
Article 15(4) of the Electricity Directive provides that Member States may foresee
priority dispatch of generation facilities using fuel from indigenous primary energy
fuel sources to an extent not exceeding, in any calendar year, 15 % of the overall
primary energy necessary to produce the electricity consumed in the Member State
concerned;
Article 16(2)(a) of the Renewable Energies Directive obliges Member States to
provide for either priority access or guaranteed access to the grid-system of
electricity produced from renewable energy sources;
Article 16(2)(c) of the Renewable Energies Directive obliges Member States to
ensure that when dispatching electricity generating installations, transmission
system operators shall give priority to generating installations using renewable
energy sources in so far as the secure operation of the national electricity system
permits and based on transparent and non-discriminatory criteria;
Similarly to the provisions under the Renewable Energies Directive, Article 15 (5)
b) and c) of the Energy Efficiency Directive foresee priority grid access and priority
dispatch of electricity from high-efficiency cogeneration respectively.
-
-
-
The introduction of priority dispatch and priority access for renewable energies on the one
hand and for CHP on the other hand are closely related. According to the impact
assessment of the Energy Efficiency Directive, Article 15 (5) aims at ensuring a level
playing field in electricity markets and help distributed CHP. Thus, the obligation of
priority dispatch, and the right to priority access, already existing under its predecessor,
Directive 2004/8/EC, have been expanded in the Energy Efficiency Directive to include
5
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mandatory priority access for CHP
1
. The new provision fully mirrored the provision under
the then new Renewable Energies Directive.
Already for Directive 2004/8/EC, priority dispatch and (the right for a Member State to
foresee) priority access were based on the "need to ensure a level playing field" and the
challenges for CHP being similar to those for renewable energies. The provision of priority
dispatch and priority access for CHP has thus since its beginning been closely related to
the provision of these rights to renewable energies. This is also reflected in the text of
Article 15(5) itself, which provides that "when
providing priority access or dispatch for
high-efficiency cogeneration, Member States may set rankings as between, and within
different types of, renewable energy and high-efficiency cogeneration and shall in any case
ensure that priority access or dispatch for energy from variable renewable energy sources
is not hampered."
The current framework thus provides that the provision of priority dispatch and priority
access for CHP shall under no circumstance endanger the expansion of renewable energies.
Against this background, any change to the framework for renewable energies would
directly impact the justification underlying the introduction of priority dispatch and priority
access for CHP.
The degree to which Member States have made use of the right under Article 15 (4) of the
Electricity Directive differs significantly. Some Member States make no use of it whereas
other Member States provide for priority dispatch of power generation facilities using
national resources (most notably coal). The provisions in the Renewable Energy Directive
and Energy Efficiency Directive are mandatory and in principle applied in all Member
States, although the implementation can differ significantly due to differences in national
subsidy schemes.
Deficiencies of the current legislation
European legislation allows the option (as regards indigenous resources) or sets an
obligation (for RES E and CHP) to implement priority dispatch and (for RES E and CHP)
priority grid access. This creates a framework with very high predictability of the total
power generation per year, thus increasing investment security. In particular in view of the
increasing share of RES E, this has resulted in a situation where in some Member States
very high shares of power generation are coming from "prioritized" sources.
The EU has committed to a continued increase of the share of renewable generation for the
coming decades. Until 2030, at least 27 % of final energy consumption in the EU shall
come from RES E
this requires a share of at least 45 % in power generation
2
. According
to the PRIMES EuCo27 scenario, decarbonisation of EU's energy system would require a
share of RES in power generation of close to 50%, wind and solar energy alone projected
to cover 29 % of power generation.
1
2
https://ec.europa.eu/energy/sites/ener/files/documents/sec_2011_0779_impact_assessment.pdf,
p.58.
2030 Communication, COM(2014) 15 final, p.6.
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Today, investments in renewable generation make up the largest share of investments;
many RES E technologies can no longer be treated as marginal or emerging technologies.
The comparison of Germany and Denmark, two Member States with high shares both of
RES E and CHP, is helpful to assess the deficiencies of systems based on strong priority
dispatch and priority access principles. Taking the example of Denmark, an average of 62
% of power demand in the month of January 2014 has come from wind generation alone
3
and the share of annual demand covered by wind power has risen from 19 % in 2009 to 42
% in 2015
4
. Adding to this the share of 50.6 % of CHP in total Danish power generation
5
,
which makes Denmark one of the Member States with the highest share of CHP
6
, in many
periods almost all generation would be subject to "priority dispatch". Finally, it may be
necessary to add certain generation assets which are needed to operate for system security,
e.g. because only they can provide certain system services (e.g. voltage control, spinning
reserves), further limiting the scope for fully market based generation. However, in
Denmark, market incentives on generators are set in a way that drastically reduces the
impact of priority dispatch. Almost all decentralized CHP plants and a large number of
wind turbines would be exposed to and are not willing to run at negative prices. As CHP
are not shielded from market signals by national support systems, they have strong
incentives to stop electricity generation in times of oversupply. The integration of a high
share of RES E and CHP in parallel has been successful to a significant extent because
CHP are
not
built and operated on the basis of a "must run" model, where heat demand
steers electricity generation. To the contrary, CHP plants have back-up solutions (boilers,
heat storage), and use these where this is more efficient for the electricity system as
expressed by wholesale prices.
Taking the example of another "renewables front runner", Germany, "must run"
conventional power plants have been found to contribute significantly to negative prices
in hours of high renewable generation and low load, with at least 20 GW of conventional
generation still active even at significantly negative prices
7
. Financial incentives are so that
many conventional plants generate even at significantly negative prices, with many power
plants switching off electricity generation only at prices around minus 60 EUR/MWh. This
increases the occurrence of negative prices, worsening the financial outlook for both
renewable and conventional generators, and can increase system stress and costs of
interventions by the system operator. This is not due to technical reasons
also in
Germany, CHP plants generally have back-up heat capacities, which are already necessary
to address e.g. maintenance periods of the main plant, or could technically install these.
While it may be economically and environmentally efficient to run through short periods
of low prices (to avoid ramping up or down), this is no longer the case where the market
3
4
5
http://www.martinot.info/renewables2050/how-is-denmark-integrating-and-balancing-renewable-
energy-today.
http://www.energinet.dk/EN/El/Nyheder/Sider/Dansk-vindstroem-slaar-igen-rekord-42-procent.aspx.
https://ec.europa.eu/energy/sites/ener/files/documents/PocketBook_ENERGY_2015%20PDF%20final.
pdf, p. 183.
http://www.code2-project.eu/wp-content/uploads/Code-2-D5-1-Final-non-pilor-Roadmap-
Denmark_f2.pdf;
See:
http://www.netztransparenz.de/de/Studie-konventionelle-Mindesterzeugung.htm
6
7
7
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is willing to pay a lot for electricity being
not
generated. Excess electricity is in these
situations not very efficiently generated, but essentially a waste product. While there is a
wide range of reasons for conventional generation to produce at hours of negative prices
(e.g. very inflexible technologies such as nuclear or lignite which need a long time to
reactivate), approximately 50 % of the plants in such a situation in Germany had at least
the capability for parallel heat production, and approximately 8-10 % of conventional
plants still producing at such moments were found to be heat-controlled CHP generation
8
.
In view of the EU target for at least 27 % of renewable energies in final energy
consumption (which according to PRIMES EuCo27 projections would require 47 % of
gross final electricity consumption to come from renewable energy), the high share of
priority dispatch and priority access-technologies will increasingly occur in other Member
States. This can have very significant impact on the well-functioning of the electricity
market. In particular:
-
Subsidy schemes based on priority dispatch (such as Feed-in Tariffs) often are
based on high running hours and a mitigation of market signals to the subsidized
generator. This means that non-subsidized generation is increasingly pushed out of
the market even where this is not cost-efficient;
Situations in which more than 100 % of demand is covered by priority dispatch
become more prevalent. This lowers the investment security provided by priority
dispatch, and can lead to results contrary to policy interests such as unnecessary
curtailment of RES E;
The internal energy market depends on steering the use of generation by price
signals. In a situation where the clear majority of power generation does not react
to price signals, market integration fails and market signals cannot develop;
Incentives to invest into increased flexibility which would naturally result from
price signals on a functioning wholesale market do not reach a significant part of
the generation mix. Priority dispatch rules can eliminate incentives for flexible
generation (e.g. biomass, some CHP with back-up installations) to use the
flexibility potential and instead create incentives to run independent of market
demand;
Priority dispatch and priority grid access limit the choice for transmission system
operators to intervene in the system (e.g. in case of congestion on certain parts of
the electricity grid). This can result in less efficient interventions (e.g. re-
dispatching power plants in suboptimal locations). The increased complexity with
high shares of priority dispatch could also lower system stability, although
emergency measures may also affect generation benefiting from priority dispatch;
Priority dispatch rules for high marginal cost technologies can result in using costly
primary ressources to generate electricity at a time where other, cheaper,
technologies were available;
Priority dispatch rules for generation installations using indigenous ressources
result in clear discrimination of cross-border flows and distortions to the internal
market.
-
-
-
-
-
-
8
Consentec,
"Konventionelle Mindesterzeugung
Einordnung, aktueller Stand und perspektivische
Behandlung",
Abschlussbericht 25. Januar 2016, p. vii and 25.
8
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Against this background, the provision of priority dispatch and priority grid access needs
to be reassessed in view of the main policy objectives of sustainability, security of supply
and competitiveness (see also Section 7.4.2 of the evaluation).
Presentation of the options
For the operation of generation assets, it is recognized that the wholesale market with
merit-order based dispatch and access ensures an optimal use of generation resources.
Especially in balancing, it also ensures optimal use of congested network capacities. Rules
which deviate from these provisions reduce system efficiency and result in market
distortions, as it can sometimes be economically more efficient to curtail RES and the
guarantee of non-curtailment significantly increases price volatility
9
. Where financial
compensation on market-based principles is foreseen in case of re-dispatch, priority
dispatch also does not appear to be necessary to mitigate investor risk in low marginal cost
technologies. Thus, it is proposed to abolish or at least significantly limit the exceptions
foreseen under EU law from merit-order based dispatch and network access.
Option 0: do nothing
This option does not change the legislative framework. Priority dispatch and access
provisions remain unchanged in EU legislation and the above-described problems persist.
Option 0+: Non-regulatory approach
Stronger enforcement would not adress the policy objectives. In fact, as the objective is to
ensure market-based use of generation assets with limited exceptions, stricter enforcement
of existing obligations under EU law which make those exceptions mandatory would be
counter-productive.
Voluntary cooperation does not change the legislative framework and thus maintains the
currently existing obligations. The order of dispatch for power plants and access to the grid
has clear cross-border implications. Priority dispatch/access often results in lower
availability of cross-border capacities, and significant differences in these rules can thus
distort cross-border trade.
Option 1: Abolish priority dispatch and priority access
Under this option, priority dispatch / priority access provisions would be removed from
EU legislation, and replaced by a general principle that generation and demand response
shall be dispatched on the basis of using the most efficient resources available, as
determined on the basis of merit order and system capabilities.
This option would optimally achieve the defined objectives and thus be highly effective.
It would however result in additional administrative impact for very small RES E
installations which are currently not capable of controlling their feed-in into the grid
(notably rooftop solar) and micro-CHP installations. Furthermore, it could increase
complexity and prolong the development time for emerging technologies. As these
technologies would not yet be mature they would not be able to generate at competitive
9
KEMA study commissioned for the EU Commission (ENER/C1/427-2010, Final report of 12 June
2014), p.183 f.
9
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prices and could thus not reach a number of running hours needed to generate sufficient
experience.
Option 2: Limit priority dispatch and/or priority access to emerging technologies and/or
small plants
Under this option, priority shall be given only where it can be justified to enable a certain
technology or operating model which is seen as beneficiary under other policy objectives.
As regards emerging technologies
10
, this could in particular be linked to ensuring that the
technologies reach a minimum number of running hours as required to gather experience
with the non-mature technology. For particularly small generation installations
11
, this
could reduce the administrative and technical effort linked to dispatching the power plant
for its owner, which may appear disproportionate for certain installations. This being said,
the administrative effort can be significantly reduced by ensuring the possibility of
aggregation, allowing the joint operation and management of a large number of small
plants. To mitigate negative impacts on market functioning, both possible exemptions
should be capped to ensure that priority dispatch and priority access does not apply to large
parts of total power generation.
This option would achieve the defined objectives, although certain trade-offs would be
made. Accepting priority dispatch and access for certain installations would reduce market
efficiency. If the share of exempted installations in the total electricity market remains low,
the negative market impact is however likely to remain very limited. On the other hand,
the positive impact of allowing the development of new technologies can provide a
significant benefit for the achievement of renewable energy targets in the medium to long-
term. Exempting very small installations would also increase public acceptance and reduce
administrative efforts required from the operators of these installations, which are often
households. This is thus the preferred option, although it has to be ensured that exemptions
remain limited to a small part of the market. The exact definition of the emerging
technologies could be left to subsidiarity.
Option 3: Abolish priority dispatch and introduce clear curtailment and re-dispatch rules
to replace priority access
This option (which can be combined with Option 2) would entail the abolishment of
priority dispatch. Priority grid access would be replaced by clear rules on how to deal with
situations of system stress, in particular as regards congestion of grid elements. In
principle, market-based ressources should be used first, thus curtailing or redispatching
first those generators which offer to do this against market-based compensation. In a
second step, where no market-based ressources can be used, minimum rules on
compensation are foreseen, ensuring compensation based on additional costs or (where this
is higher) a high percentage of lost revenues.
10
11
In the PRIMES EuCo27 scenario, the emerging technologies of tidal and solar thermal generation (other
technologies having insignificant shares) are projected to have a total installed capacity of 7.26 GW and
produce 10 TWh of electricity in 2030 (13 GW and 20 TWh in 2050, respectively).
In the PRIMES EuCo27 scenario, RES E small-scale capacity is projected in 2030 to be 85 GW (7.8 %
share) and produce 96 TWh of energy (2.9% share).
10
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It would mean that network operators would obtain a clear incentive to make an assessment
on the basis of costs as to the alternatives available to them to address the underlying
network constraints, thereby creating opportunities for more innovative solutions such as
storage.
The increase in transparency and legal certainty would notably also prevent discrimination
against certain technologies (particularly RES E) in curtailment and re-dispatch decisions.
RES E are often operated by smaller market players, who could otherwise be subject to
excessive curtailment or unable to achieve fully equal compensation. It would also foresee
principles on the financial compensation to be paid in case of curtailment or re-dispatch,
thus reducing the additional investment risk linked to losing priority access and thereby
reducing any increase in capital costs. In order to ensure effective implementation of the
new market rules prior to abolishment of priority dispatch and access, priority dispatch and
access may be maintained for an interim period after entry into force of the other measures
adressing Problem 1.
Increased transparency and legal certainty on curtailment and re-dispatch are a "no regret"
measure, in so far as they contribute to market functioning even in the absence of changes
to the priority dispatch and priority access framework. Ensuring sufficient compensation
for curtailment, notably for RES E, will increase costs to be borne by system operators. In
so far as these costs are currently integrated into renewable subsidy schemes, total system
costs will however remain similar. As regards priority grid access, this is the preferred
option, in order to ensure that the abolishment of priority grid access has no unwanted
negative consequences on the financial framework notably of RES E but also of CHP.
Comparison of the options
It should be noted that the removal of priority dispatch and priority access does not equally
affect different technologies and generators in different Member States:
-
The removal of priority dispatch mostly affects high marginal cost technologies
(biomass, indigenous resources, some CHP), as low marginal cost technologies
(wind, PV) are generally dispatched when available already on the basis of the
merit order. Without priority dispatch, high marginal cost technologies thus take
up a role more generally associated with other high marginal cost plants, such as
gas-fired power plants, operating only in periods of high prices (high residual load).
Those generators are then incentivized to making best use of the inherent flexibility
that their technology can provide to a power system, and thus accompany the
change to an electricity system with a high share of variable low marginal cost
generation. For high marginal cost generation, removal of priority dispatch can
significantly reduce the number of running hours. Studies for the Commission have
shown a reduction of approximately 85 % in dispatch of wood-based biomass
generation, mostly to the benefit of gas-fired power plants
12
. To the contrary, there
is a (more limited) increase in the running hours of low marginal cost generation,
including wind and solar;
12
For this assessment, biomass was assumed to consist of 22 % "must-run" waste incineration (OPEX: 3.6
EUR EUR/MWh) and 78 % wood-fired plants with high variable costs (around 90 EUR EUR/MWh)
11
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-
The reduction in inefficient biomass dispatch would represent a major part of the
significant reductions of system costs presented in Figure 1 below, with annual
savings of 5.9 billion Euros, expected by the removal of market distortions under
Problem Area I, Option (1a) of the impact assessment
13
;
Figure 1: Reduction in system costs by abolishment of priority rules
Source: METIS
-
By achieving market-based dispatch, the removal of priority dispatch for all
technologies drastically reduces the occurrence of negative prices. Whereas
negative prices can be a normal occurrence in well-functioning markets which have
opportunity costs linked to not offering a service (as is the case on the electricity
markets), the occurrence of negative prices based on priority rules shows that
priority is given also in times where the system does not require additional
generation.
13
For more details please see Section 6.1.2 of the impact assessment.
12
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Figure 2: reduction of negative price occurrences by removal of priority
dispatch
Source: METIS
-
-
-
The removal of priority access on the other hand mostly affects technologies which
are producing in areas and at times of network congestion. This will more often
concern low marginal cost technologies (especially wind) as periods of high wind
feed in are more likely to result in congested network elements, requiring
curtailment or re-dispatch;
Providing clear and transparent rules on curtailment and compensation benefits all
market actors. This is particularly true for small and/or new market actors,
including RES E;
While the change of biomass dispatch to reflect its role as flexible back-up
generation, to the benefit mostly of gas, but also of coal and nuclear generation
thus would drastically reduce future system costs, it could possible entail an
increase of CO2 emissions in the power sector, whereas total CO2 emissions under
the ETS framework would in principle remain identical over time
14
.
Option 1 would be the most effective in achieving the objective of non-discrimination and
market efficiency. However, it could result in an increase of costs to achieve other policy
objectives, notably for decarbonisation of the energy system. Fully removing priority
dispatch and access would also result in an increased need for small generators, including
households (e.g. rooftop solar) to participate in the electricity market. While this would
allow strong economic incentives, it would thus increase the administrative impact for
households and SMEs. Thus, clear and transparent rules for the market participation of
RES E and CHP as well as limited exemptions for small and emerging technologies should
be included, to accompany the phase-out of priority access and priority dispatch. On the
other hand, remaining at the
status quo
would, with a growing share of priority
technologies in the system, seriously undermine effective price formation and dispatch in
the wholesale market. The preferred option is thus a combination of Options 2 and 3. This
14
The environmental impacts from the removal of priority dispatch for biomass are discussed in Section
6.1.6 of the impact assessment
13
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will allow a reduction of the administrative impact for households and SMEs while
ensuring the most efficient use of bigger mature power generators.
Subsidiarity
Priority dispatch is foreseen directly in EU law. Changing or removing those provisions
cannot be achieved on a national level. Furthermore, in an integrated electricity market,
the way to determine which power plant is operated has a direct impact on cross-border
trade. Applying discriminatory provisions for power plant dispatch in certain Member
States can thus negatively affect cross-border trade or even directly result in discrimination
against power generators in other Member States. Ensuring efficient market integration
and functioning investment signals, requires fundamental dispatch rules to be harmonized.
Stakeholders' opinions
In the public consultation, most stakeholders support the full integration of Renewable
energy sources into the market, e.g. through full balancing obligations for renewables,
phasing-out priority dispatch and removing subsidies during negative price periods. Many
stakeholders note that the regulatory framework should enable RES E to participate in the
market, e.g. by adapting gate closure times and aligning product specifications. A number
of respondents also underline the need to support the development of aggregators by
removing obstacles for their activity to allow full market participation of renewables.
Also stakeholders from the renewable sector often recognize the need to review the priority
dispatch framework. They make this however subject to conditions; Wind Europe provided
views on curtailment of wind power and priority dispatch and stated that "countries
with
well integrated day-ahead, intraday and balancing market and a good level of
interconnections, where priority of dispatch is not granted to CHP and conventional
generators, do not need to apply priority of dispatch for wind power."
They argue that "in
general, priority dispatch should be set according to market maturity and liberalisation
levels in the Member State concerned, but also taking due account of progress in grid
developments and application of best practices in system operation."
According to its
paper from June 2016 on curtailment and priority dispatch, in the view of Wind Europe
15
,
some EU markets, such as Sweden and the UK, which have relatively high penetration
rates of wind, do not offer priority dispatch for wind producers
16
and this does not place
any restrictions on market growth. However, a phase-out of priority dispatch for renewable
energies should only be considered if (i) this is done also for all other forms of power
generation, (ii) liquid intraday markets with gate closure near real-time, (iii) balancing
markets allow for a competitive participation of wind producers; (short gate closure time,
separate up/downwards products, etc.), and (iv) curtailment rules and congestion
management are transparent to all market parties. According to Wind Europe, these
requirements are already in 2016 fulfilled in certain markets such as the UK, Sweden and
Denmark, whereas other Markets currently still required priority dispatch. It is the view of
the Commission services that by entry into force of the present legislative initiative, the
above requirements are met in all Member States.
15
16
https://windeurope.org/wp-content/uploads/files/policy/position-papers/WindEurope-Priority-
Dispatch-and-Curtailment.pdf.
The Commission services interpret this to mean that, while priority dispatch may be foreseen under
national legislation, it has no practical impact.
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Regarding priority access, Wind Europe asks for curtailments to be valued by the market
as a service to ensure system security. It should be treated as downward capacity and its
price should be set via the balancing market. This would already be applied in the Danish
and UK markets. Participation of wind in the balancing markets could lead to a significant
reduction of curtailments. This is taken into account in Option 3, which ensures the primary
use of available market-based ressources prior to any non-market based curtailment.
Where balancing ressources are available, including from RES E, and capable of adressing
the system problem underlying the planned curtailment, they thus have to be used before
non-market based curtailment takes place. For this second step, transparent compensation
rules are foreseen. Wind Europe recognizes that
"there may be a benefit from not
compensating 100% of the opportunity cost. Reducing slightly the income could send an
important incentive signal to investors to select locations with existing sufficient network
capacity, Curtailment would then be likely to occur less frequently. The exact % of the
opportunity cost needs to be carefully assessed in order to find a balance between an
increase in policy cost and the increase of financing costs due to higher market risk."
This
position is reflected in the present proposal.
Stakeholders from the cogeneration sector underline the link to priority dispatch for
renewable energies. COGEN Europe submits that it is "important
that at EU level CHP
benefits from at least parity with RES on electricity provisions, as long as there are no
additional policy measures that would compensate for the loss in optimal operation
ensured through priority of dispatch for certain types of CHPs."
They also argue that
"while
a significant fraction of the CHP fleet can be designed and/or retrofitted to operate
in a more flexible way (e.g. though partial load capabilities, enhanced design from the
electrical components, and the heat storage addition), this may come at the expense of the
site efficiency and industrial productivity."
The parallelism to RES is maintained in all
options, whereas the additional costs and possible loss of efficiency have to be balanced
with the economic cost of significant amounts of inflexible conventional generation in a
high-RES system.
EUROBAT, association of European Manufacturers of automotive, industrial and energy
storage batteries, regards curtailing of energy as a system failure, as the "wasted" power
should be stored in batteries instead. It argues against any financial compensation to
renewable generators for being curtailed, as such a compensation would disincentivize the
installation of energy storage systems
17
.
Transmission system operators would be directly affected, as they are responsible for
practical implementation of the priority rules. In May 2016, ENTSO-E has asked their
Members to provide answers to questions which had been discussed with the Commission
services. 29 TSOs from 25 countries have replied, though not all TSOs answered all
questions, which is also due to the limited impact of priority dispatch/access in some
Member States (with a low share of CHP and RES E). TSOs from 14 Member States
answered that priority dispatch increases the costs of pursuing stable, secure and reliable
system operations. TSOs from a smaller group of Member States (4 to 6) also stated that
priority dispatch limits the possibilities to keep the grid stable, secure and reliable. Only
the TSOs of three Member States answered that priority dispatch has no major effect on
system operations. Regarding the market impact, TSOs from 12 Member States raised
17
http://www.eurobat.org/sites/default/files/eurobat_batteryenergystorage_web.pdf
p.28.
15
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increased dispatching costs and 9 raised the occurrence of negative prices. On the other
hand, TSOs from one Member State argued that priority dispatch resulted in reduced costs
for the support of RES E. TSOs also stressed the cross-border impact of priority dispatch:
TSOs from 6 Member States referred to increased congestion of interconnectors, and an
example provided was that priority dispatch in neighbouring areas impacted the system
operation in the TSOs area. When asked how European legislation should adress the issues
mentioned, no TSO wanted to retain priority dispatch, 8 TSOs wanted to retain it with
exemptions, 4 TSOs wanted a phase out of priority dispatch, and 13 TSOs wanted priority
dispatch to be removed entirely.
16
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1.2. Regulatory exemptions from balancing responsibility
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Summary table
Objective:
To ensure that all technologies can compete on an equal footing, eliminating provisions which create market distortions unless clear necessity is demonstrated, thus ensuring that
the most efficient option for meeting the policy objectives is found. Each entity selling electricity on the market should be responsible for imbalances caused.
Option 0
Option 1
Option 2
Option 3
Do nothing.
This would maintain the
status
quo,
expressly requiring financial
balancing responsibility only under
the State aid guidelines which
allow for some exceptions.
Lowest political resistance
Full balancing responsibility for all parties
Each entity selling electricity on the
market has to be a balancing responsible
party and pay for imbalances caused.
Balancing responsibility with exemption
possibilities for emerging technologies
and/or small installations
This would build on the EEAG.
Balancing responsibility, but possibility to delegate
This would allow market parties to delegate the
balancing responsibility to third parties.
This option can be combined with the other options.
Description
Shielding from balancing responsibilities
creates serious concerns that wrong
incentives reduce system stability and
endanger market functioning. It can increase
reserve needs, the costs of which are partly
socialized. This is particularly relevant if
those exemptions cover a significant part of
the market (e.g. a high number of small RES
E generators).
Most suitable option(s): Option 2
combined with the possibility for delegation based on freely negotiated agreements.
Costs get allocated to those causing them.
By creating incentives to be balanced,
system stability is increased and the need
for reserves and TSO interventions gets
reduced. Incentives to improve e.g.
weather forecasts are created.
Financial risks resulting from the
operation of variable power generation
(notably wind and solar power) are
increased.
Cons
Pros
This could allow shielding emerging
technologies or small installations from the
technical and administrative effort and
financial risk related to balancing
responsibility.
The impact of this option would depend on the
scope and conditions of this delegation. A
delegation on the basis of private agreements, with
full financial compensation to the party accepting
the balancing responsibility (e.g. an aggregator)
generally keeps incentives intact.
The impact of this option would depend on the
scope and conditions of this delegation. A full and
non-compensated delegation of risks e.g. to a
regulated entity or the incumbent effectively
eliminates the necessary incentives. Delegation to
the incumbent also results in further increases to
market dominance.
18
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Description of the baseline
Balancing responsibility refers to the obligation of market actors (notably power
generators, demand response providers, suppliers, traders and aggregators) to
deliver/consumer exactly as much power as the sum of what they have sold and/or
purchased on the electricity market. Predictions for demand and (to a more limited extent)
generation being not 100 % precise, market actors are often not fully balanced. The
Transmission System Operator then ensures that total demand and supply are maintained
in balance by activating (upward or downward) balancing energy, often coming from
dedicated balancing capacities.
Balancing responsibility implies that the costs of the balancing actions taken by the
transmission system operator are generally to be compensated by the market parties which
are in imbalance. In some Member States, certain types of power generation (notably wind
and solar, but possibly also other technologies such as biomass) are excluded from this
obligation or have a differentiated treatment. Most Member States foresee some degree of
balancing responsibility also for renewable generators; based on an EWEA (now Wind
Europe) study, in 14 out of 18 Member States with a wind power share above 2-3 % in
annual generation, wind generators had some form of balancing responsibility
18
. This
however does not always translate into real financial responsibility of the generator for
imbalances it caused. In Austria for example, a public entity, OEMAG, acts as balancing
responsible party for all subzidized renewable generation, thus shielding individual
generators from imbalance risks of their power plants
19
and collectively purchasing/selling
balancing energy for the renewable sector
20
. On the other hand, in a small number of
Member States balancing costs imposed on renewable power generation can be
prohibitively high and almost reach the level of wholesale prices (e.g. incurred balancing
costs of up to 24 EUR/MWh in Bulgaria and 8-10 EUR/MWh in Romania)
21
.
Article 28 (2) of the Balancing Guideline provides that
"each balance responsible party
shall be financially responsible for the imbalance to be settled with the connecting TSO".
This does not, however, preclude frameworks in which market actors are (fully or partly)
shielded from the financial consequences of imbalances caused by having this
responsibility shifted to another entity. This is part of some current support schemes.
The EEAG provide that in order for State aid to be justified, RES E generators need to bear
full balancing responsibility unless no liquid intra-day market exists. The EEAG rules
however do not apply where no liquid intraday market exists, and and also do not apply to
installations with an installed electricity capacity of less than 500 kW or demonstration
projects, except for electricity from wind energy where an installed electricity capacity of
3 MW or 3 generation units applies. The exemption from balancing responsibility in the
absence of liquid intra-day markets is based on the reasoning that were liquid intra-day
18
19
20
21
http://www.ewea.org/fileadmin/files/library/publications/position-papers/EWEA-position-paper-
balancing-responsibility-and-costs.pdf,
p. 5-6.
https://www.energy-
community.org/portal/page/portal/ENC_HOME/DOCS/2014187/0633975ACF8E7B9CE053C92FA8
C06338.PDF
http://www.oem-ag.at/de/oekostromneu/ausgleichsenergie/.
http://www.ewea.org/fileadmin/files/library/publications/position-papers/EWEA-position-paper-
balancing-responsibility-and-costs.pdf
p. 8.
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markets
do
exist, they allow renewable generators to drastically reduce their imbalances
by trading electricity on short-term markets and thus taking account of updated wheather
forecasts. This shows that imposition of balancing responsibility is thus closely linked to
the creation of liquid short-term markets, one of the main objectives of the electricity
market design initiative.
The corollary to balancing responsibility is the possibility to participate in the balancing
market, offering balancing capacity to the TSO against remuneration. This is further
described under Section 5.1.1.4 and closely linked to the Balancing Guideline.
Deficiencies of the current legislation
Already today, the increased share of renewable energies in power generation
(approximately 29% in 2015) has significant impact on market functioning and grid
operation. This effect is most noticeable in Member States with RES E shares above the
EU average.
The below figure shows two relevant weeks, with production and consumption shown
together. In the left graph, generation exceeds the load (red line) in situation with lots of
solar power generation (yellow). In the right graph, less renewable power is generated
(blue, green, yellow, but minimal PV (yellow)). Supply and demand of electricity has to
match at all times despite changes in demand and variable renewable electricity
production. For both situations, flexibility options such as storage, demand side response,
flexible generation and interconnection import/export capacities are needed to take up
electricity.
Figure 1: Volatility in the German power market in June and December 2013
Source: Agora Energiewende 2013.
To integrate renewable production progressively and efficiently into a market that
promotes competitive renewables and drives innovation, energy markets and grids have to
be fit for renewables. This is not necessarily the case in many jurisdictions since markets
have traditionally been designed to cater the needs of conventional generation rather than
variable renewables. To make markets fit for renewables means developing adequately the
short-term markets such as intraday and balancing. This also means allowing, to the
maximum possible extent, renewables to participate in all electricity markets on equal
footing to conventional generation removing all existing barriers for renewable energy
20
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sources integration. Integrating RES E into the market and allowing them to generate a
large part of their revenues from market prices requires an increase of flexibility in the
system, which is also needed for absorbing cheap renewable electricity at times of high
supply. It is for this reason that the EEAG (para.124) requires generators to be subject to
standard balancing responsibilities only unless no liquid intra-day market exists. Liquid
intra-day markets should exist in all Member States at the expected date of entry into force
of the revised legislation, accompanying the present impact assessment. However, the
term "liquid intra-day market" allows significant margin of interpretation and can thus
cause uncertainty on the application of one of the fundamental rules on the electricity
market. It will be necessary to further clarify this exemption and ensure that market actors
have legal certainty as to whether they have to bear balancing responsibility or not.
Investment incentives should take into account the value of generation at different times
of the day or of the year. Progress has been made in this area, with support schemes relying
increasingly (but not everywhere or for all generation) on premiums instead of fixed feed-
in tariffs. Where premium-based support schemes are used, the degree of market exposure
depends on their exact implementation, differing e.g. between fixed and floating premium
models, and for the latter relative to the determination of the base price used for the
calculation of the premium. Full exposure to market signals may e.g. make a different
generation installation more efficient although it produces lower total output (such as
orienting PV to the west to increase output later in the day). By exposing generators to the
financial consequences of imbalances caused, the incentives given to generators do not
relate only to optimizing the expected generation of their power plant in view of market
needs, but also to ensuring that the electricity they sell on the market matches as closely as
possible the power produced at a certain point in time. In a questionnaire to TSOs
organized by ENTSO-E, the example was given that following the attribution of balancing
responsibility in a Member State, the average hourly imbalance of PV installations
improved from 11.2 % in 2010 to 7.0 % in March 2016, and the average hourly imbalance
of wind improved from 11.1 % to 7.4 % over the same period.
Where RES E generators do not assume balance responsibility identical to other generators
and participate in the balancing market, they lack incentives for efficient operational and
investment decisions
22
. Part of this challenge is the need to avoid inacceptable risks for
RES E investors by imposing balance responsibilities without creating the market
flexibility which allows staying balanced
23
. Whereas many Member States already foresee
some balancing responsibility for RES E generators (2013: 16 Member States)
24
this is not
22
23
24
KEMA study commissioned for the EU Commission (ENER/C1/427-2010, Final report of 12 June
2014), p.185
KEMA p. 185:
"Experience from some EU countries has shown that RES generators are able to provide
less volatile and more predictable generation schedules if so incentivized by balancing arrangements."
http://ec.europa.eu/energy/sites/ener/files/documents/com_2013_public_intervention_swd04_en.pdf
Appendix I table 6.
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yet the case for all Member States, and the degree of balancing responsibility differs
considerably between Member States. This can result in market distortions, directing
investments to Member States with lower degree of responsibility rather than to those
Member States where electricity demand and renewable generation potential are optimal,
and can also result in lower liquidity of short-term markets.
Reduced balancing responsibility can also result in increasing imbalances in electricity
trades. Whereas the TSO will generally, via the balancing market, be capable of covering
imbalances, a high degree of imbalances reduces predictability of system operation and
can increase system stress (e.g. by reducing the volume of available reserves) or increase
costs for system stability (e.g. if higher reserve volumes are procured in advance).
Finally, it should be noted that the EEAG already foresees the need to phase out
exemptions from balancing responsibilities in the post-2020 period
25
. The EEAG itself
provides in its paragraph 108 that the Guidelines
"apply to the period up to 2020 but should
prepare the ground for achieving the objectives set in the 2030 framework, implying that
subsidies and exemptions from balancing responsibilities should be phased out in a
degressive way".
Refrence is also made to Section 7.4.2 of the evaluation.
Presentation of the options
Balancing responsibility of all market parties active on the electricity market is a
fundamental principle of EU energy law. This principle should not be included only in a
State aid guideline and in the Balancing Guideline but ensured at the level of secondary
law, thus increasing transparency and legal certainty. Exemptions currently foreseen in the
guidelines need to be reassessed and, where still necessary, further clarified. It should also
be further clarified in how far and under which conditions delegation of this responsibility
is possible. It is thus proposed to establish a general rule that all market-related entities or
their chosen representatives shall be financially responsible for their imbalances, and that
any such delegation/representation shall not entail a disruption of incentives for market
parties to remain balanced. Provisions in this direction are already included in the
Balancing Guideline which will be discussed in Comitology in the second half of 2016.
General principles and, where applicable, exemptions shall be integrated into the
Electricity Directive for added clarity and legal certainty.
Option 0: do nothing
This would mean that balancing responsibility remains subject only to State aid rules and
the rules in the Balancing Guideline. Fundamental principles of electricity market
operation should systematically not be decided upon only in acts adopted under the
Comitology process and guidelines which undergo no legislative process. Furthermore, the
25
Paragraph 108 EEAG reads: "These
Guidelines apply to the period up to 2020. However, they should
prepare the ground for achieving the objectives set in the 2030 Framework. Notably, it is expected that
in the period between 2020 and 2030 established renewable energy sources will become grid-
competitive, implying that subsidies and exemptions from balancing responsibilities should be phased
out in a degressive way. These Guidelines are consistent with that objective and will ensure the transition
to a cost-effective delivery through market-based mechanisms."
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EEAG are limited in time to 2020 and uncertainty as to the extent of their exemptions and
their applicability post-2020 will persist. According to their paragraph 108, it is expected
that in the period between 2020 and 2030 established renewable energy sources will
become grid-competitive, implying that subsidies and exemptions from balancing
responsibilities should be phased out in a progressive way (and thus assuming liquid short-
term markets to develop). Finally The State aid guidelines only apply to those parts of
measures which are to be seen as State aid. This concerns most, but not necessarily all,
generation which may not be fully balancing responsible. For some aspects the
qualification as State aid could potentially be put into question.
Option 0+: Non-regulatory approach
As national law is extremely varied to date, without a clear and transparent framework
setting out the degree of balancing responsibility, enforcement of existing rules (e.g. State
aid rules) is unlikely to result in a uniform and non-discriminatory legal framework.
Voluntary cooperation can contribute to reducing the negative impact of imbalances.
Imbalance netting by transmission system operators already achieves significant cost
reductions. However, voluntary cooperation does not provide sufficient legal certainty and
the minimum degree of harmonization to avoid distortions in cross-border trade. In fact,
shielding certain market parties fully or in part from balancing responsibilities creates
economic advantages which can distort cross-border trade in electricity. Where a lack of
balancing responsibility results in increased imbalances, this will negatively impact the
whole synchronous area, and thus create costs and risks for system stability also in other
Member States.
Option 1: Full Balancing responsibility for all parties
This would entail that the principles of the Balancing Guideline imposing all market-
related entities and their representatives to be financially responsible for imbalances caused
would be integrated into the Electricity Directive.
This option would thus significantly increase transparency and legal certainty. Balancing
responsibility is already an accepted concept under the EEAG, so that the market impact
would be limited to those entities currently benefitting from exemptions or not subject to
State aid rules. While this option would optimally achieve the defined objective, the
complete abolishment of the existing exemptions could result in increased administrative
effort for small installations or demonstration projects using emerging technologies.
Option 2: Balancing responsibility with exemption possibilities for emerging technologies
and/or small installations
This would allow Member States to foresee that certain emerging technologies and/or
small installations (e.g. rooftop solar) are shielded from the direct financial impact of
imbalances they cause. As imbalances need to be covered by some entity, this could be
achieved by allocating it to public bodies (essentially meaning that these entities are acting
as sellers of RES E on the wholesale market), the costs of which are then socialized.
This option addresses the currently existing exemptions under EEAG, based on the
assumption that short-term markets have developed sufficiently by the time of entry into
force of the proposed legislation to require balancing responsibility of generators not
covered by the exemptions. Without introducing additional limitations, these exemptions
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would however risk reducing effectiveness in achieving the policy objective. This is
notably the case for small installations, which under some scenarios can account for a
significant part of total electricity supply.
Option 3: Possibility to delegate balancing responsibility
This option would entail the right to delegate balancing responsibilities to a third party.
Whereas the freely negotiated delegation to a third party against financial compensation
(e.g. an aggregator) can reduce administrative impact without reducing the incentive to
reduce imbalances (as their cost will be passed on to the generator in some way), regulated
delegations without compensation drastically reduce or eliminate the incentive to remain
balanced.
The possibility to delegate on the basis of free negotiation, against financial compensation,
(combined with exemptions notably for demonstration projects and possibly very small
installations) is the preferred option. It fully achieves the policy objectives, and allows
notably smaller installations to reduce administrative efforts without reducing market
incentives.
Comparison of the options
The requirement of full balancing responsibility does not affect all renewable technologies
in the same manner. Biomass and other non-variable technologies are generally capable of
being balanced to the same degree as conventional generators. Variable generators
(especially wind and PV) can increasingly predict their generation based on wheather
forecasts, but have a higher margin of error in those predictions than conventional
generators. To reduce the margin of error, those technologies need to improve wheather
forecasts, as well as sell electricity for shorter time periods in advance, when better
forecasts become available.
A study using METIS has shown very significant reductions in frequency restoration
reserve needs due to the introduction of balancing responsibilities for RES E. Whereas
FCR and aFRR needs relate to short-term frequency deviations and are thus not
significantly affected by balancing responsibility, mFRR needs are based on longer-lasting
deviations from indicated schedules. By creating incentives for improved forecasts and
more exact schedules, reserve needs are thus significantly reduced.
24
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Figure 2: reduction in reserve needs depending on balancing responsibility
Source: METIS
Option 1 would be most effective at achieving the objective of well-functioning markets.
All exemptions from balancing responsibility, even if only partly shielding against the
financial impact of imbalances, reduce the incentive to be balanced. The complete
abolishment of the existing exemptions would however result in increased administrative
effort for small installations or demonstration projects using emerging technologies. This
could slow down roll-out of new RES E technologies and could thus render the
achievement of the decarbonisation objective more costly. Options 2 and 3 can be
combined to ensure a maximum degree of balancing responsibility with the potential to
delegate this responsibility, which allows reduction of the additional administrative impact
imposed especially on small installations. This being said, small installations are currently
often not active on the market, and it could be excessive to require balancing responsibility
even taking into account the possibility to delegate. The preferred option is thus a
derogation from balancing responsibilities for demonstration projects and small generation
(e.g. rooftop solar), and the right for other projects to delegate their balancing responsibility
against financial compensation. This significantly reduces the administrative effort for
households and small and medium enterprises (who will often continue to benefit from
exemptions from balancing responsibilities) but takes account of the increased role
renewable generation plays in the market, and the improved capabilities particularly of
larger generators to predict their output and reduce or hedge remaining imbalance risks.
Subsidiarity
Balancing responsibility is a fundamental principle in every electricity market. It ensures
that market agreements are also reflected in the physical reality, and that the costs of
imbalances created are born by those creating them. Balancing responsibiltity impacts both
investment decisions and trading on electricity markets; every decision to sell electricity
25
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on the market entails the risk to be in imbalance, which thus has to be integrated into
bidding strategies. Deviations on a national level in an integrated market could result in
distortions of cross-border trade, e.g. by making investments into variable generation in
one Member State significantly more interesting than in other Member States, and basic
principles for balancing responsibility thus need to be harmonized.
Furthermore, increasing the share of RES E in the total energy consumption is an EU
target. For 2030, a target binding at EU level exists, without nationally binding targets;
therefore the EU has to ensure the EU target is reached. With an increasing share of RES
E, they become a relevant player on the power markets. As power markets are increasingly
integrated, this has direct cross-border impact. Equal treatment to all generation
technologies should be ensured to avoid market distortions. Markets should be fit to allow
all generation technologies and demand to compete on equal footing, while allowing the
EU to reach the policy objectives of sustainability, competitiveness and security of supply.
The increasing share of RES E also creates challenges for network operation. In
synchronous areas even exceeding the EU, this is an issue which cannot be resolved at
national level alone.
Stakeholders' opinions
In the public consultation, most stakeholders support the full integration of renewable
energy sources into the market, e.g. through full balancing obligations for renewables,
phasing-out priority dispatch and removing subsidies during negative price periods. Many
stakeholders note that the regulatory framework should enable RES E to participate in the
market, e.g. by adapting gate closure times and aligning product specifications. A number
of respondents also underline the need to support the development of aggregators by
removing obstacles for their activity to allow full market participation of renewables. The
approach chosen in the State aid guidelines found broad support by most stakeholders.
Wind Europe's predecessor EWEA submitted
26
that in 14 out of 18 Member States, wind
generators were already balancing responsible in financial or legal terms, generally subject
to the same rules as conventional generation. However, in some Member States, balancing
costs for renewable generators appeared discriminatorily high. Important considerations
for wind generators to accept balancing responsibility were, for EWEA: (i) the existence
of a functioning intra-day and balancing market, (ii) balancing market arrangements
providing for the participation of wind power generators, as e.g. shorter gate closure time
and procurement timeframes, (iii) market mechanisms that properly value the provision of
non-frequency ancillary services for all market participants including wind power, (iv) a
satisfactory level of market transparency and proper market monitoring, (v) sophisticated
forecast methods in place in the power system and (vi) the necessary transmission
infrastructure. While forecast methods should be developed by the market and cannot be
provided directly in policy (which can only give incentives for such methods to be
improved and used), the market design initiative aims at achieving all these points.
In its consultation of national TSOs, ENTSO-E also adressed questions on balancing
responsibility. TSOs in five Member States answered that after introduction of balancing
26
http://www.ewea.org/fileadmin/files/library/publications/position-papers/EWEA-position-paper-
balancing-responsibility-and-costs.pdf
26
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responsibilities, RES E generators were more motivated to conclude energy production
contracts which are close to the real production in each market time unit; for four Member
States, better forecasts were used by RES E generators. 1 TSO provided figures according
to which the average hourly imbalance of PV installations improved from 11.2 % in 2010
to 7.0 % in March 2016, and the average hourly imbalance of wind improved from 11.1 %
to 7.4 % over the same period.
27
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1.3. RES E access to provision of non-frequency ancillary services
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Summary table
Objective: transparent, non-discriminatory and market based framework for non-frequency ancillary services
Option 0
Option 1
Option 2
BAU
Description
Description
Different requirements, awarding procedures and Set out EU rules for a transparent, non-discriminatory and Set out broad guidelines and principles for Member States for the
remuneration schemes are currently used across market based framework to the provision of non-frequency adoption of transparent, non-discriminatory and market based
Member States. Rules and procedures are often tailored ancillary services that allows different market players framework to the provision of non-frequency ancillary services.
to conventional generators and do not always abide to /technology providers to compete on a level playing field.
transparency, non-discrimination. However increased
penetration of RES displaces conventional generation
and reduces the supply of these services.
Stronger enforcement
Pro
Pro
Provisions containing reference to transparency, non- Accelerate adoption in Member States of provisions that Sets the general direction and boundaries for Member States
discrimination are contained in the Third Package. facilitate the participation of RES E to ancillary services as without being too prescriptive.
However, there is nothing specific to the context of non- technical capabilities of RES E and other new technologies is Allows gradual phase-in of services based on local/regional needs
frequency ancillary services.
available, main hurdle is regulatory framework.
and best practices.
Clear regulatory landscape can trigger new revenue streams
and business models for generation assets.
Con
Con
Resistance
from
Member
States
and
national Possibility of uneven regulatory and therefore market developments
authorities/operators due to the local/regional character of depending on how fast Member States act. This creates uncertain
non-frequency ancillary services provided.
prospects for businesses slowing down RES E penetration.
Little previous experience of best practices and unclear how
to monitor these services at DSO level where most RES E is
connected.
Most suitable option(s): Option 2
is best suited at the current stage of development of the internal electricity market. Ancillary services are currently procured and sometimes used in very
different manners in different Member States, Furthermore, new services are being developped and new market actors (e.g. batteries) are quickly developing. Setting out detailed rules required
for full harmonisation would thus preclude unknown future developments in this area, which currently is subject to almost no harmonisation.
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Description of the baseline
The delivery of
frequency
related ancillary services by RES E assets is partly covered by
the Balancing Guideline.
Non-frequency
ancillary services are services procured or mandated by TSOs that support
the electricity network, such as voltage support, short circuit power, black start capability,
synthetic inertia or congestion management. They are in most cases supplied by electricity
generators, but can in some cases also be supplied by demand facilities, electricity storage
or network equipment.
Currently, the procurement of non-frequency anciliary services is not regulated at EU-
level. The situation in Member States for the provision of
non-frequency
ancillary services
is determined by national grid codes that
inter alia
specify the rules for connection of
generation assets to the electric network infrastructure. Grid codes are evolving
continuously, but a snapshot taken recently through studies funded by the European
Commission
27
, a survey commissioned by ENTSO-E
28
and by examining the actual
national grid codes, reveals that several approaches are considered in Europe across more
than a dozen Member States (as well as Norway and Switzerland) surveyed. The snapshot,
summarized in Figures 1 to 3, focuses only on the provision of reactive power, i.e. voltage
related ancillary services, one of the most important non-frequency ancillary services. It is
important to point out that the overview is partial and does not cover all specific
arrangements TSOs might have. For instance in Denmark, these services are not generally
remunerated, however in certain periods of the year when thermal plants are not operating,
these services are remunerated to guarantee sufficient supply.
27
"REserviceS project"
(2014) Intelligent Energy Europe programme,
http://www.reservices-project.eu/
28
"Survey on Ancillary Services Procurement and Electricity Balancing Market Design"
(2015) ENTSO-
E,
https://www.entsoe.eu/Documents/Publications/Market%20Committee%20publications/WGAS%20Su
rvey_04.05.2016_final_publication_v2.pdf?Web=1
31
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Figure 1: Grid code requirements for generators on reactive power
Source: National grid codes, ENTSO-E survey, REserviceS project
Figure 2: Procurement procedure of reactive power
Source: National grid codes, ENTSO-E survey, REserviceS project
32
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Figure 3: Remuneration of reactive power delivery
Source: National grid codes, ENTSO-E survey, REserviceS project
Currently the practises with regard to requirements, procurement and renumeration of non-
frequency anciliary services can be summarised as follows:
-
Requirements: most Member States demand mandatory provision from
conventional generators and in some cases specific provisions are considered for
RES E, mostly wind. The latter approach is in line with the Commission Regulation
(EU) 2016/631 establishing a network code on requirements for grid connection of
generators ('RfG');
Procurement: a majority of Member States procure these services through bilateral
agreements and only in a small minority of Member States market based tenders
are used. In other Member States both bilateral agreements and market based
tenders are used;
Remuneration: about half of the surveyed Member States do not have a mechanism
to remunerate the service, the other half does remunerate them either by capability,
utilisation or a combination of both. In some Member States, a bonus is given to
RES E for upgrading the infrastructure.
Deficiencies of the current legislation
The current EU regulatory framework defines in Article 12 lit. d) of the Electricity
Directive the role of the TSO: it includes ensuring the availability of all necessary ancillary
services. However, there is nothing specific with regard to non-frequency ancillary
services. The RfG specifies extensively requirements for the provision of reactive power
by different power modules. However, it does neither address the procedures by which
such services should be awarded (e.g; a market based mechanism), nor whether they should
be remunerated (as such or on the basis of what criteria e.g. capacity, utilisation or a
combination thereof). Additionally, the RfG is not likely to lead to an efficient deployment
of reactive power capability on the territory as voltage support services have a geographical
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dimension and need to be provided in specific locations. This might lead to an oversupply
of reactive power capability (with associated increased costs born by the generators) and
at the same time underutilization of installed capability because they are not suitably
located. The System Operation Guideline aims at ensuring that TSOs use market-based
mechanisms as far as possible to ensure network security and stability, but does not
articulate further this high level principle.
The current legislation is insufficient and needs to be adapted to trends observed in the
market where studies project that the demand for non-frequency ancillary services across
Europe will increase over the coming decades, mainly because of increased RES E
penetration. A technical and economical study by Électricité de France (EDF)
29
concluded
that
"it is essential that variable RES production which is displacing conventional
generation is also able to contribute to the provision of ancillary services and also
potentially provide new services (e.g. inertia)".
A study commissioned by the German
Energy Agency Dena
30
found that
"due to increasing transport distances and international
power transit, the demand for reactive power in the transmission grid will increase
significantly by 2030."
Presentation of the options
Option 0 - BAU
In a business-as-usual scenario, non-frequency ancillary services are mainly provided by
large conventional generators. Although those services are currently not remunerated in all
Member States, TSOs would need those generators to run even if not profitable. Therefore
such generators would request additional revenues. This scenario prevent the access to
additional revenue streams for new types of generation assets, mainly being RES E.
Since RES E are displacing conventional generation assets, the supply of these services is
becoming scarcer. As a result, generation from RES E would be curtailed at certain times
to guarantee the safe operation of the electric network. This would likely slow down the
deployment of RES E and affect negatively the achievement of the European wide
renewable energy consumption targets by 2020 and 2030 and related climate goals.
Option 0+: Non-regulatory approach.
The Third Package does not address the provision of non-frequency ancillary services in a
way that could be used to enforce existing legislation stronger. Voluntary cooperation does
not provide the necessary minimum degree of harmonization and legal certainty to allow
for efficient cross-border trade. Even where non-frequency anciliary services have to be
provided on a local level, the provision of and revenues from these services can have a
significant impact on the competitiveness of electricity generation, which competes cross-
border.
29
30
"Technical and Economic analysis of the European Electricity System with 60% RES"
(2015) Alain
Burtin & Vera Silva,
http://www.energypost.eu/wp-content/uploads/2015/06/EDF-study-for-download-
on-EP.pdf
"Dena Ancillary Services Study 2030"
(2014) German Energy Agency,
http://www.dena.de/en/projects/energy-systems/dena-ancillary-services-study-2030.html
34
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Option 1 - EU rules setting out a framework for a transparent, non-discriminatory, market
based framework
This option would imply setting EU wide harmonized rules in EU legislation on
requirements of generators for connection to the grid, on specifications and procurements
of products to ensure a level-playing field and fair remuneration of these services. This
would encounter a number of issues: even though the provision of non-frequency ancillary
services is necessary to run a European wide electricity market, due to the local/regional
character of these services, optimal solutions may vary across Member States.
Additionally, it would require the coordination of both transmission and distribution
system operators as a large fraction of RES E is installed at the distribution level. These
services are not generally remunerated at lower voltage levels and no clear framework is
yet available on how to regulate these services. Finally, there are still significant challenges
for market based integration of ancillary services from RES E due to limitations of
predictability of energy output.
Option 2 - Guidelines setting out the principles for the adoption of a transparent, non-
discriminatory, market based framework.
The aim is to provide a sound basis for the development of a non-discriminatory,
transparent and market based access to non-frequency ancillary services by RES E and to
allow the gradual phase-in of services based on local/regional needs and best practices.
This is a pre-requisite for a cost efficient allocation of resources to provide the necessary
supply of non-frequency ancillary services. The measures should be articulated along the
following main lines:
-
ensure that the regulatory requirements for the provision of these services are
rational with respect to the expected needs (both in terms of quantity and location)
and non-discriminatory with respect to different assets capable of providing the
service.
bring transparency to the way ancillary services are procured, for instance through
market-based tenders or auctions and allow sufficient flexibility in the process to
accommodate bids from assets with different technical characteristics;
promote mechanisms for remuneration by system operators;
consult stakeholders when establishing new rules to make sure all assets can
participate to these services while providing support for safe grid operation.
-
-
-
These measures are also conducive to a higher penetration of RES E in the electricity
network and could be further developed in a dedicated network code.
Comparison of the options
The BAU scenario would not be effective in designing a level-playing field for a non-
discriminatory, transparent and market based access to non-frequency ancillary services
and in achieving the objectives of increasingly integrated RES E in a European electricity
market. It would also be an obstacle for further increase of RES E in the generation mix
with a potential negative impact on the achievement of the 2030 targets. In the current
situation, where ancillary services are provided by conventional generators, curtailment of
RES E is required at times to assure the availability of generation assets capable of
providing ancillary services (so-called "must run"). The decision to keep these resources
online is not based on economic assessments, but only on operational considerations for a
safe operation of the grid. Such constraint would not exist or not to the same extent if RES
35
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E resources would be used to their fullest potential to provide non-frequency ancillary
services.
Options 1 and 2 would be more effective in providing a non-discriminatory, transparent
and market-based environment for RES E and new technologies to offer and compete for
the provision of non-frequency ancillary services. Companies, especially owners of RES
E assets would benefit from additional revenue streams from ancillary markets.
Extrapolating the European wide market size for non-frequency ancillary services from
national markets (typically in the range of tens of millions of euros) puts it roughly in the
range of a few billion euros.
In addition, the investment outlook for additional power plants would be better for owners
of RES E assets. Taking Ireland as a best practice case, regulators and TSOs are
redesigning the ancillary service market in such a way that RES E can participate. It
requires introducing new services and allowing these services to be remunerated. This has
the additional benefit that the electricity generation share of RES E in such a redesigned
market can be higher without compromising the safe operation of the grid and allows
system operators to make efficiency gains: the Irish All Island TSOs compared the
estimated costs of enhancing the operational capabilities of ancillary services with the
benefits of lower market prices coming from a larger share of wind energy generation.
They concluded that the benefit outwheighted the costs already at System Non-
Synchronous Penetration levels below 50%
31
.
Based on the studies and sources mentioned in this and other Sections of this annexe, little
uncertainty exists about the benefits of more transparent provision of ancillary services,
one where RES E could participate. For certain services, especially those that have a
limited geographical scope, it is unclear if and how liquid markets could be established,
with regulated cost+ payments being a possible alternative.
The second Option is preferred over the first one, because at this moment there is not
enough evidence to support European wide harmonized rules for non-frequency ancillary
services. New services are being developed and new market players are emerging. The
first option could preclude unknown future developments in this area, whereas the second
option allows the gradual phase-in of services based on local/regional needs and best
practices.
Subsidiarity
Even though non-frequency anciliary services, such as voltage related ancillary services
have a local character, it does not prevent action through the market design initiative. The
efficient provision of these services is a critical enabler of an integrated European
electricity market and of higher RES E penetration. Also, the assets that provide non-
frequency ancillary services are largely the same ones providing frequency-related
services: a local problem due to voltage stability could have implications for the provision
of frequency-related services and the stability of the grid at a European level as a whole.
Finally, the assets providing ancillary services are generally competing in other markets
31
"Onshore wind supporting the Irish grid"
(2013) Andrej Gubina,
http://www.reservices-project.eu/wp-
content/uploads/D5.1-REserviceS-Ireland-case-study-Final.pdf
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with a larger geographical scope, including the day ahead and intraday electricity markets.
Conditions on voltage control thus have an impact on cross-border competition in
electricity markets.
Stakeholders' opinions
RES E
32
and demand response
33
industry associations and owners of storage
34
assets assert
the technical availability to provide non-frequency ancillary services, but expose
difficulties accessing the market because of non-transparent rules for contracting,
minimum product size and other product specifications, as well as procurement lead times.
Younicos, a storage provider, states that
"storage is not defined in regulatory framework
on national or EU level, creating uncertainty on market access and creating uncertainty
on ownership roles."
Similarly, the Association of European Manufacturers of automotive,
industrial and energy storage batteries (EUROBAT), calls for a legislative definition of
storage which allows system operators to own and operate battery storage. The association
calls for the value of services offered by storage systems, including voltage control,
frequency control and ramp control, to be financially recognized. Anciliary services should
thus be compensated
35
. The European Wind Energy Association points out that the reactive
power requirements at low active power set points imposed on RES E in the frame of the
RfG code could potentially have a substantial negative impact on the investment costs of
new wind power plants..
Energinet.dk considers increased competition for the supply of ancillary services
"as a part
of the continuous development of the energy only market with the objective to create clear
price signals and creating socio economic benefits and security of supply on short and
long run".
Geographical requirements for delivery of ancillary services is a challenge in
developing these markets as well as the fact that grid components such as
"synchronous
compensators and HVDC VSC-convertors have a potential to deliver system supporting
services in competition with commercial power plants. This development demands
transparency in the procurement process to secure optimal planning, operations and
investments"
36
.
Two joint papers by Statkraft and Dong Energy point out that
"in the past, system services
have played a marginal role in total economics of power plants. In the future, however,
system services will be more important for the individual plant and the value (balance of
32
"Balancing responsibility and costs of wind power plants"
(2015) European Wind Energy Association,
http://www.ewea.org/fileadmin/files/library/publications/position-papers/EWEA-position-paper-
balancing-responsibility-and-costs.pdf
33
"Mapping Demand Response in Europe today"
(2015) Smart Energy Demand Coalition,
http://www.smartenergydemand.eu/wp-content/uploads/2015/09/Mapping-Demand-Response-in-
Europe-Today-2015.pdf
34
"Technical and regulatory aspects of the provision of ancillary services by battery storage"
(2015)
Younicos
35
"Battery Energy Storage in the EU: barriers, opportunities, services and benefits"
(2016) EUROBAT,
http://www.eurobat.org/sites/default/files/eurobat_batteryenergystorage_web.pdf p.30.
36
"Markets for ancillary and system supporting services in Denmark" (2016) Energinet.dk
37
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supply and demand of these services) to the system are likely to be markedly higher",
and
that
"requirements put into tenders are crucial for the outcome".
37
37
"Does the wholesale electricity market design need more products, or more control?"
Part 1 (2015) &
Part 2 (2016) Dong Energy & Statkraft
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2. D
ETAILED MEASURES ASSESSED UNDER
P
ROBLEM
A
REA
I,
S
TRENGTHENING SHORT
-
TERM MARKETS
OPTION
1(
B
)
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2.1. Reserves sizing and procurement
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Summary table
Objective:
define areas wider than national borders for sizing and procurement of balancing reserves
Option 0: business as usual
Option 1: national sizing and procurement
Option 2: regional sizing and procurement of
of balancing reserves on daily basis
balancing reserves
The baseline scenario consists of
This option involves the setup of a binding
a smooth implementation of the
This option consists in developing a
regulation requiring TSOs to use regional
binding regulation that would require TSOs platforms for the procurement of balancing
Balancing Guideline. Existing
on-going experiences will
to size their balancing reserves on daily
reserves. Therefore this option foresees the
probablistic methodologies. Daily
remain and be free to develop
implementation of an optimisation process for
further, if so decided. However,
calculation allows procuring lower
the allocation of transmission capacity between
sizing and procurement of
balancing reserves and, together with daily
energy and balancing markets, which then
balancing reserves will mainly
procurement, enables participation of
implies procuring reserves only a day ahead of
remain national as foreseen in
renewable energy sources and demand
real time
.
the Balancing Guideline.
response.
This option would result in a higher level of
This option foressees separate procurement
coordination between European TSOs, but still
of all type of reserves between upward (i.e.
Active participation in the
relies on the concept of local responsibilities of
Balancing Stakeholder Group
increasing power output) and downward
individual balancing zones and remains
could ensure stronger
(i.e. reducing power output; offering
compatible with current operational security
enforcement of the Balancing
demand reduction) products.
principles.
Guideline.
Pro
optimal national sizing and
Pro
–regional
areas for sizing and procurement
procurement of balancing reserves
of balancing reserves
Option 3: European sizing and procurement of
balancing reserves
This option would have a major impact on the
current design of system operation procedures
and responsibilities and current operational
security principles. A supranational
independent system operator ('EU ISO') would
be responsible for sizing and procuring
balancing reserves, cooperating with national
TSOs. This would enable TSOs to reduce the
security margin on transmission lines, thus
offering more cross-zonal transmission
capacity to the market and allowing for
additional cross-zonal exchanges and sharing
of balancing capacity.
Description
Pros
Pro
single European balancing zone
Con
extensive standardisation through
replacement of national systems, difficult and
costly implementation
Most suitable option(s) Option 2.
Sizing and procurement of balancing reserves across borders require firm transmission cross-zonal capacity. Such reservation might be limited by the
physical topology of the European grid. Therefore, in order to reap the full potential of sharing and exchanging balancing capacity across borders, the regional approach in Option 2 is the
preferred option.
Cons
Con
no cross-border optimisation of
balancing reserves
Con
balancing zones still based on national
borders but cross-border optimisation possible
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Description of the baseline
Balancing refers to the situation after markets have closed (gate closure) in which a TSO
acts to ensure that demand is equal to supply. A number of stakeholders are responsible
for organising the electricity balancing market:
-
Transmission system operators ('TSOs') keep the overall supply and demand in balance
in physical terms at any given point in time. This balance guarantees the secure
operation of the electricity grid at a constant frequency of 50 Hertz.
-
Balance responsible parties ('BRPs') such as producers and suppliers; keep their
individual supply and demand in balance in commercial terms. Achieving this requires
the development of well-functioning and liquid markets. BRPs need to be able to trade
via forward markets and at the day-ahead stage. They also need to be able to fine-tune
their position within the same trading day (e.g. when wind forecasts or market positions
change).
-
Balancing service providers ('BSPs') such as generators, storage or demand facilities,
balance-out unforeseen fluctuations on the electricity grid by rapidly increasing or
reducing their power output. BSPs receive a capacity payment for being available when
markets have closed ('balancing capacity' also referred to as 'balancing reserve') and an
energy payment when activated by the TSO in the balancing market ('balancing
energy'). Payments for balancing capacity are often socialized via the transmission
network tariffs, whereas payments for balancing energy usually shape the price that
BRPs who are out of balance have to pay ('imbalance price').
Currently, national balancing markets in Europe have significantly different market
designs and are operated according to different principles
38
. To achieve efficiency gains
through a genuine European balancing market, it is essential to provide a set of common
principles. As one can expect the adoption of the Balancing Guideline in 2017, it is possible
to agree on the baseline, which can be built upon in the market design initiative.
The Balancing Guideline covers, in particular:
-
Standardisation of balancing products
39
used by TSOs to maintain their system in
balance. The starting point is a situation where, in Europe, the number of balancing
products is estimated at some hundred. TSOs will have to reduce this number as much
as possible to create a harmonised competitive market.
-
Merit order activation of balancing energy based on European platforms, i.e.
operational within 4 years after the entry into force, where all TSOs will have access
while taking into account cross-zonal transmission capacity available or released after
intraday gate closure.
-
Single marginal pricing ('pay-as-cleared') which reflects scarcity for the remuneration
of the participants in the balancing market (i.e. the payment that a participant receives
for providing balancing energy to be the same payment as the imbalance price). Thus
being individually in imbalance but contrary to the imbalance of the system as a whole,
38
39
ENTSO-E survey on ancillary services, May 2016:
https://www.entsoe.eu/Documents/Publications/Market%20Committee%20publications/WGAS%20Su
rvey_04.05.2016_final_publication_v2.pdf?Web=1
The term "product" refers to different balancing services which can be traded, such as the provision of
balancing energy with different speeds of delivery.
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thus helping the system as a whole to stay balanced, gets rewarded rather than
penalized.
-
Harmonisation of the length of the imbalance settlement periods ('ISP' i.e. the time over
which it is measured whether BRPs stay in balance, i.e. they did not sell more
electricity than they produced). Trading products are generally not shorter than, but
can be multiples of ISP. The length of the ISP is thus of relevance for all market
timeframes and not just for the balancing market. In cross-border trade, the biggest
common ISP has to be used. Thus, the smallest trading product across Europe is
currently 60 minutes which corresponds to the length of the longest ISP across Member
States. However, where two Member States have shorter ISPs, shorter products can be
traded across their border (e.g. 30 minutes between France and Germany). To increase
the trade of short products, the Balancing Guideline proposes a shift to harmonized 15
minutes ISPs
40
.
The Balancing Guideline also provides the baseline for integrating renewable energy
sources and demand response in the balancing market, in particular:
-
Balancing energy gate closure time (i.e. the point in time after which there can be no
more balancing energy offers from BSPs) as close as possible to physical delivery, and
at least after intraday cross-zonal gate closure (thus a maximum of 60 minutes before
real time). Shorter gate closure time allows wind or PV generators and demand
response aggregators to update their forecast and to offer remaining energy to the
electricity balancing market.
-
Possibility to offer balancing energy without a balancing capacity contract. The
procurement timeframes for balancing capacity have generally long lead times for
which wind or PV power producers and demand response aggregators cannot secure
firm capacity.
-
Shorter procurement timeframes for balancing capacity (close to real time).
It would be, however, out of the scope of the Balancing Guideline to aim for full
harmonization of the currently very diverse balancing markets. The Balancing Guideline
includes many exemptions (e.g. central dispatch systems, procurement rules for balancing
capacity) and possible derogations (e.g. dual pricing as opposed to single marginal
pricing). It is therefore essential that all national balancing markets adhere to a minimal set
of common principles.
In addition, balancing reserves are currently mainly sized and procured by TSOs on a
national level (except for the Nordic countries and the Iberian Peninsula). This contrasts
with the increasing demand for balancing reserves across Europe over the coming decades
which is mainly due to large-scale cross-border flows and high volumes of variable RES
E generation. Most of the TSOs are sizing their balancing reserves based on potential
outages of HVDC interconnectors and forecast errors of renewable energy sources. Despite
40
"Frontier
Economics report on the harmonisation of the imbalance settlement period",
April 2016
https://www.entsoe.eu/Documents/Network%20codes%20documents/Implementation/CBA_ISP/ISP_
CBA_Final_report_29-04-2016_v4.1.pdf
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trends observed in the market (see below figure from ELIA, the Belgian TSO)
41
on the
evolution of balancing reserves needs from 2013 to 2018, no significant binding
harmonisation is achieved on this subject in the Balancing Guideline.
Graph 1: Interpolated ranges for the volume of reserves needed between 2013 and
2018
Source: Belgian TSO report on the evolution of ancillary services needs to balance the Belgian control
areas towards 2018, pp. 32)
In their Market Monitoring report 2014
42
, ACER points out that in most European markets,
the procurement of balancing capacity represents the largest proportion of the overall costs
of balancing. The excessive weight of the balancing capacity procurement costs may
suggest that the procurement of balancing capacity is not always optimised. ACER
emphasis the importance of optimising the procurement costs of balancing capacity,
including separate procurement of upward and downward balancing capacity and shorter
procurement timeframes.
41
42
Belgian TSO report on the evolution of ancillary services need to balance the Belgian control area
towards 2018, May 2013
http://www.elia.be/~/media/files/Elia/Grid-data/Balancing/Reserves-Study-2018.pdf
"Market Monitoring Report 2014"
(2015) ACER, pp. 210.
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Graph 2: Overall costs of balancing (capacity and energy) and imbalance charges
over national electricity demand in a selection of European markets
2014
(euros/MWh)
Source:
"Market
Monitoring Report 2014"
(2015) ACER,
pp. 209
Moreover, because only flexible generation assets can provide balancing reserves,
balancing markets tend not to be very competitive. Balancing markets are regularly rather
concentrated on the supply side as only assets able to adjust production or consumption
fast can participate. In their Market Monitoring report 2014, ACER also illustrates the very
high level of concentration in the procurement of balancing capacity.
Graph 3: Level of concentration in the provision of balancing services from automatic
Frequency Restoration Reserves (capacity and energy) for a selection of Member
States
2014 (%)
Source:
"Market
Monitoring Report 2014" (2015) ACER, pp. 207
Integrating balancing markets will increase competition and hence will save overall costs.
These costs are largely determined by the size of the network area for which the balancing
reserves are being procured (also referred to as 'balancing zone' or 'load-frequency control
block') and the frequency with which this is done. The size of the reserves that need to be
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set aside depends on the size of unforeseen events within a given balancing zone. Larger
zones across TSO-control areas (effectively across Member States) will result in lower
total balancing reserve requirements and reduce significantly the need for back-up
generation, as the risks to be covered are smaller than with a simple addition of the risks
of two small zones. To this end, a limited number of wider balancing zones should be
defined by the needs of the network rather than national borders.
Deficiencies of the current legislation (see also Section 7.4.2 of the evaluation)
Recitals and provisions containing reference to transparent, non-discriminatory and
market-based procedures for the procurement of balancing capacity are contained in the
Electricity Directive. However, there is nothing more specific to the procurement rules. As
part of the regional cooperation of TSOs, Article 12.2 of the Electricity Regulation refers
to the integration of balancing and reserve power mechanism. However, no further details
are being developed concerning the sizing of balancing reserves at regional level.
The Guidelines on System Operation (approved in Comitology on 4
th
of May 2016)
harmonise terms, methodologies and procedures for sizing balancing reserves, but it is
expected that balancing zones (or LFC Blocks) will remain unchanged and mainly based
on national borders (except for Nordic countries and Spain-Portugal) as illustrated below.
Figure 1: Synchronous Areas, LFC Blocks (or balancing zones) and LFC Areas
Source: ENTSO-E supporting document for the Network Code on Load-Frequency Control and Reserves,
2013, pp. 42
The Balancing Guideline (not yet approved in Comitology) intends to set out rules for the
procurement of balancing capacity, the activation of balancing energy and the financial
settlement of BRPs. It would also require the development of a harmonised methodology
for the reservation of cross-zonal transmission capacity for balancing purposes. However
sharing and exchange of balancing capacity would not be mandatory under the Balancing
Guideline but encouraged.
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Presentation of the options
Option 0 - BAU
The baseline scenario consists of a smooth implementation of the Balancing Guideline
where sharing and exchange of balancing capacity are not mandatory. In this way, the
existing on-going experiences (such as the regional sizing and procurement of balancing
reserves in the Nordic countries and the Iberian Peninsula) will remain and be free to
develop further and integrate, if so decided by the participating parties. Isolated and likely
incompatible projects may be implemented across Europe.
Procurement arrangements such as shorter contracting period close to real time should be
enforced in line with the development of a methodology for the reservation of cross-zonal
transmission capacity for balancing purposes.
Option 0+: Non-regulatory approach
The Third Package does not address the provision of regional sizing and procurement of
balancing reserves in a way that could be used to stronger enforce existing legislation.
Specific parts dealing with transparency, non-discrimination and market based rules can
be found in the Article 15 of the Electricity Directive. Others parts dealing with the regional
cooperation of TSOs on balancing and the optimal allocation of capacity across timeframes
can be found in Article 12.2 and Annex 1.2.6 of the Electricity Regulation.
Voluntary cooperations between TSOs for sharing and exchaning balancing capacity could
be further supported thanks to an active participation in the Balancing Stakeholder Group
established by ACER and ENTSO-E for an early implementation of the Balancing
Guideline. However no mandatory provisions in the Balancing Guideline request TSOs to
size and procure reserves at regional level.
Option 1
National sizing and procurement of balancing reserves on a daily basis
This option consists in developing a binding regulation that would require TSOs to size
their balancing reserves on daily probabilistic methodologies (i.e. based on different
variables such as RES E generation forecasts, load fluctuations and outage statistics). This
method is opposed to a deterministic approach which consists of sizing the balancing
reserves on the value of the single largest expected generation incident. Daily calculation
allows procuring lower balancing reserves and, together with daily procurement, enables
participation of renewable energy sources and demand response.
Shorter procurement timeframes for balancing capacity facilitate the participation of wind
generators and demand response aggregators which cannot secure firm capacity over long
lead times, or storage operators, which do not have to guarantee specific amounts of energy
stored over long periods. This option foresees separate procurement of all types of reserves
between upward (i.e. increasing power output; offering demand reduction) and downward
(i.e. reducing power output; offering demand increase) products.
Option 2
Regional sizing and procurement of balancing reserves
This option involves the set up of a European binding regulation requiring TSOs to use
regional platforms for the procurement of balancing reserves. Mandatory sharing and
exchange of balancing capacity requires firm cross-zonal transmission capacity. Therefore
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this option foresees the development of an optimisation process for the allocation of
transmission capacity between energy and balancing markets, which then implies
procuring reserves only a day ahead of real time.
This option thus has the focus on a more integrated approach on the sizing and procurement
of balancing reserves themselves. Mandatory regional procurement of balancing reserves
would require changing and harmonizing adjacent business and related operational
processes. Mandatory regional sizing of balancing reserves might have an impact on
system operation procedures and responsibilities, at least procedurally shifting security of
supply-related tasks (such as system's state analysis) to a supranational level (possibly to
newly-established regional operational centres ('ROCs'), see also Section 2.3).
TSOs would still be responsible for real-time activation of the balancing capacity procured;
however they would only have access to the regional platforms for the procurement of
balancing capacity which would assume harmonized procurement timeframes and
centralised optimisation algorithm requiring firm cross-border transmission capacity to be
available. Balancing reserves would be estimated on a daily basis and based on
probabilistic methodologies.
Option 3
European sizing and procurement of balancing reserves
This option would result in a significant evolution of the current design in which European
electricity systems are operated. This would have a major impact on the current design of
system operation procedures and responsibilities.
This option involves setting up a binding European framework to ensure that all Member
States implement a single market design for sizing and procurement of balancing reserves.
A supranational independent system operator ('EU ISO') would be responsible for sizing
and procurement of balancing reserves, cooperating with national TSOs. This would
enable TSOs to reduce the security margin on transmission lines, thus offering more
transmission capacity to the market and allowing for additional sharing and exchanges of
balancing capacity.
Comparison of the options
Economic impacts
All three options can capture some of the potential social welfare opportunities. Option 3
would be the most effective in achieving an optimal sizing and procurement of balancing
reserves at European level. However, it might not be feasible as sharing and exchanges of
balancing capacity require firm cross-zonal transmission capacity. Such reservation might
be limited by the physical topology of the European grid (e.g. geographical distribution of
the balancing reserves to maintain operational security
43
). Option 1, which foresees daily
sizing of balancing reserves at national level and separate procurement of downward and
upward balancing capacity, would result in an increased participation of wind power
producers and demand response aggregators in the balancing market. While the
improvements of national rules regarding sizing and procurement of balancing reserves
43
ENTSO-E supporting document for the Network Code on Load-Frequency Control and Reserves, 2013,
pp. 75
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would allow savings around EUR 1.8 billion, it would not reap the full potential of cross-
border exchanges. Daily sizing and procurement of balancing reserves could therefore be
optimally performed at regional level. The preferred option is thus Option 2, which brings
savings of around EUR 3.4 billion.
Table 1: Economic impacts by option
Balancing reserves needs (GW)
Balancing reserves needs reduction
Annual savings (EUR billion)
Source: METIS
BAU
53.4
-
-
Option 1
52.1
3%
1.8
Option 2
29.9
44%
3.4
Option 3
17.1
68%
4.5
Regulatory impact
The costs of sizing and procuring balancing reserves at regional level are mainly linked to
the possibility to add a task to the newly-established regional operational centres ('ROCs')
(see also Section 2.3 of the present annexes to the impact assessment). System state
analysis would have to be performed on a daily basis and regional level by the ROCs,
together with the setting-up of regional plaforms for the procurement of balancing reserves.
The option entailing the smallest change (Option 1) involves costs significantly less than
the other two options. Option 2 is likely to be more expensive as a result of the additional
tasks to ROCs and the setting-up of several new platforms for the exchange or sharing of
balancing reserves.
Subsidiarity
The subsidiarity principle is fulfilled given that the EU is best placed to provide for a
harmonised EU framework for common sizing and procurement of balancing reserves.
Most Member States currently take national approaches to size and procure balancing
reserves including often not allowing for foreign participation. As common sizing and
procurement of balancing reserves requires neighbouring TSOs' and NRAs' full
cooperation, individual Member States might not be able to deliver a workable system or
only provide suboptimal solutions.
Providing mandatory regional sizing and procurement of balancing reserves would be also
in line with the proportionality principle given that it aims at preserving the properties of
market coupling and ensuring that the distortions of uncoordinated national balancing
mechanisms are corrected and the internal market is able to deliver the benefits to
consumers.
Stakeholders' opinions
Most respondents from the Market Design consultation agreed with the need to speed up
the development of integrated short-term (balancing and intraday) markets. A significant
number of stakeholders argue that there is a need for legal measures, in addition to the
technical network codes and guidelines under development, to speed up the development
of cross-border balancing markets, and provide for clear legal principles on non-
discriminatory participation in these markets.
In ENTSO-E's view a parallel harmonization of balancing energy and balancing capacity
procedures would lead to unreasonably high effort for TSOs and would introduce
additional uncertainty and insecurity for the operation of the electricity system if made
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mandatory. However ENTSO-E and ACER recognise that common cross-border
procurement of reserves is a good target in the long-term.
The March 2016 Electricity Regulatory Forum (the "Florence Forum"), a forum for
stakeholders to engage on wholesale market regulatory issues, made the following relevant
conclusion:
"The Forum stresses the importance of balancing markets for a well-integrated and
functioning EU internal energy market. It encourages the Commission to swiftly bring the
draft Balancing Guideline to Member States for discussion, ideally before the summer,
with a view to reaching agreeement in autumn this year. It considers, however, that there
may still be improvements needed and ask the Commission to consider the provisions of
the draft Guideline carefully before presenting a formal proposal.
The Forum supports the view that further steps are needed beyond agreement and
implementation of the Balancing Guideline. In particuler, further efforts should be made
on coordinated sizing and cross-border sharing of reserve capacity. It invites the
Commission to develop proposals as part of the energy market design initiative, if the
impact assessment demonstrates a positive cost-benefit, which also ensure the effectiveness
of intraday markets."
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2.2. Removing distortions for liquid short-term markets
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Summary table
Objective: to remove any barriers that exist to liquid short-term markets, specifically in the intraday timeframe, and to ensure distortions are minimised.
Option 0
Business as usual
Local markets mostly unregulated, allowing for national
differences, but affected by the arrangements for cross-
border intraday and day-ahead market coupling.
Option 1
Fully harmonise all arrangements in local
markets.
Option 2
Selected harmonisation, specifically on issues relating to gate closure
times and products.
Description
Stronger enforcement and volunatry cooperation
There is limited legilsation to enforce and voluntary
cooperation would not provide certainty to the market.
Simplest approach, and allows the cross-border
arrangements to affect local market arrangements. Likely to
see a degree of harmonisation over time.
Would minimise distortions, with very limited
opportunity for deviation.
Targets issues that are particularly important for maximising liquidity
of short-term markets and allows for participation of demand response
and small scale RES.
May still be difficult to implement in some Member States with
implication on how the system is managed
central dispatch systems
could, in particular, be impacted by shorter gate closure time.
Pros
Differences in national markets will remain that can act as a
barrier.
Extremely complex; even the cross-border
arrangements have not yet been decided and
need significant work from experts.
Additional benefit unclear.
Most suitable option(s): Option 2
Provides a proportionate response targeting those issues of most relevance.
Cons
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Description of the baseline
Intraday markets usually open several hours before the day of delivery and allow market
participants to trade energy products i.e. discrete quantities of energy for a set amount of
time - close to real time and as short as five minutes before delivery.
Liquid intraday markets will form a critical part of a European energy market that is able
to cost-effectively accommodate an increasing share of variable renewable sources, allow
for more demand-side participation, and allow for energy prices to reflect scarcity.
"Liquidity is a measure of the ability to buy or sell a product
such as electricity -
without causing a major change in its price and without incurring significant
transaction costs. An important feature of a liquid market is the presence of a large
number of buyers and sellers willing to transact at all times"
44
.
Maximising liquidity in the intraday market will increase competitive pressure, increase
confidence in the resulting energy prices, and allow adjustment of positions close to real
time, thus reducing the need for TSO actions in the balancing timeframes (although it
should be noted that this will not by itself reduce the need for remedial actions by TSOs to
address congestion in internal grids).
-
The more variable source of renewable generation in the EU energy mix, the more
impact of errors in forecasting of weather and demand. Allowing close-to-real-time
trading will allow suppliers and producers to take account of the most up-to-date
information and, therefore, reduce risk of being out of balance.
The more trading in this market, the more likely it is to reflect the overall value of
staying in balance, thereby increasing confidence in the price. This in turn will
affect price formation in the day-ahead market and in forward markets.
-
Most Member States have organised intraday markets. In their Market Monitoring Report,
ACER points out a general trend to an increase in the volumes traded in national intraday
markets.
44
Ofgem,
https://www.ofgem.gov.uk/electricity/wholesale-market/liquidity
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Figure 1
ID traded volumes in selection of EU markets
2011-2014 (TWh).
Source: PXs and the CEER national indicators database (2015), as reported in "Market Monitoring Report
2014" (2015) ACER.
However, there remains significant scope for increasing liquidity. In the same report,
ACER analyse 13 markets that make up 95% of the liquidity in intraday markets, using as
a liquidity indicator the ratio of energy volumes traded to demand. The following shows
that only 5 markets had a ratio above 1%.
ES
12.1
%
IT
7.4
%
PT
7.6
%
DE
4.6
%
GB
4.4
%
SI
1.0
%
BE
1.0
%
SE
1.0
%
LT
1.0
%
FR
0.7
%
CZ
0.7
%
NL
0.2
%
PL
0.1
%
The organisation of national intraday markets is largely unregulated in EU law. A degree
of harmonisation has developed naturally, partially due to common actors in national
markets. However, significant differences still remain. In particular:
-
-
whilst most countries operate a continuous trading approach, some have intra-day
auctions;
gate closure times (i.e. when the market closes) vary from between 5 minutes (BE
and NL) to 120 minutes (HU) ahead of real time. In the Iberian market, which
operates auctions, the shortest gate closure time is just over two hours, and can
extend even further depending on the hour of delivery;
the granularity of products varies between 60 minute products and 15 minute
products;
the minimum size of bids varies between 0.1MWh to 1MWh;
the types of orders vary considerably;
demand response is not consistently allowed to participate;
whether bidding is at unit-level or portfolio-level;
whether the organised intraday-markets are exclusive (i.e. preventing bi-lateral
trading).
-
-
-
-
-
-
Currently, cross-border trading in the intraday timeframe is not harmonised, is generally
on a border-by-border basis and the total traded volumes are low: in 2014 only 4.1% of IC
capacity was used intraday, compared to 40% day-ahead.
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The CACM guideline
45
envisages a new, EU-wide cross-border market in the intraday
timeframe. Local markets will be indirectly impacted by its introduction, essentially
because it provides an extra choice for market participants on which platform to trade.
There are important interactions, notably because the two markets co-existing in this way
has the potential to split liquidity (i.e. split the trading across two markets as opposed to
one, thereby reducing the benefits of a highly liquid market). The more differences that
exist between local markets and between local markets and the cross-border market, the
greater the impact is likely to be as arbitrage opportunities between them will be reduced.
One issue exists in particular
that of gate closure times. The below diagram is an
illustration of the potential interactions between local and cross-border markets. While
both are open for trading, market participants can chose the best one, most likely driven
by price and/or products which match their needs, but potentially also by functionality and
ease-of-use of the trading platform. As such there should be a general trend towards
convergence of prices in these two markets as they will effectively be in direct competition
with each other. The more similarities in the specificities of the markets the more likely
this is to be the case. However, if the local market closes before the cross-border market,
the arbitrage opportunities are reduced as the market participants cannot freely trade
between the two. There is also a risk that local rules will mean that continued cross-border
trading will not be possible once the local market has shut, for example because it is on
this basis which the suppliers and producers provide 'firm' details on their contracted
energy to the TSO. The existence of different products and arrangements, and even
different IT systems on which to trade, also bears the risk of splitting liquidity between
different markets. However, whilst the longer-term objective should be to have one,
common market where all trading takes place and where liquidity is 'pooled', given the
starting point it is not necessarily beneficial to deliver this by harmonising all arrangements
in the short-term, as it could involve moving to the 'lowest common denominator,' as
described further below.
45
Commission Regulation (EU) 2015/1222 establishing a guideline on capacity allocation and congestion
management.
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Figure 2
Example co-existence of local and cross-border markets, where local
market closes before cross-border.
The design of some national markets may limit the ability for RES E or Demand Response
to participate, as they will prefer shorter products as this will help them accommodate more
variability in generation and demand. Also, if products do not at least reflect the imbalance
settlement period, then market participants will not have the ability to balance themselves
sufficiently frequently.
Finally, the closer to real time that market parties are allowed to trade, the more likely it is
that their supply and demand will be in balance when it comes to delivering and consuming
energy. This is especially relevant in a market sensitive to weather fluctuations where
changes can happen after the market has closed and the participants are not able to buy or
sell energy to make up for this. It therefore becomes the responsibility of the TSO as part
of the balancing market. However, the risk is that, if set too close, TSOs will not have the
time they need after being informed of the final market results to manage the system and,
in particular, deal with internal bottlenecks.
Deficiencies of the current legislation
As detailed above, there is very limited legislation in this area. The most significant piece
is the CACM Guideline, but this only indirectly addresses the operation of national markets
and, in most cases, will not directly lead to standardised trading within local markets,
which thereby potentially creates a barrier to cross-border trade and liquidity.
The Evaluation Report for market design concluded that
"the Third Energy Package does
not ensure sufficient incentives for private investments in the new generation capacities
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and network because of the minor attention in it to effective short-term markets and prices
which would reflect actual scarcity."
46
Presentation of the options
Option 0
Business as Usual
This option would leave local markets mostly unregulated, allowing for national
differences, but influenced by the arrangements for cross-border intraday and day-ahead
market coupling. The CACM Guideline requires the definition of a gate closure time on
each bidding zone border, which can be a maximum of 60 minutes. This could impact
decisions taken at national level, but this is not certain and differences are likely to remain.
Further, the definition of the products that can be taken into account in the cross-border
system are to be determined under the CACM Guideline which could, again, impact the
products which are provided in local markets.
Option 0+ Non-regulatory approach
There is very limited legislation in this area. Stronger enforcement of current rules
therefore does not provide scope to achieve a larger degree of harmoninsation of intraday
trading arrangements.
Voluntary cooperation has resulted in significant developments in the market and a lot of
benefits. However it may not provide for appropriate levels of harmonisation or certainty
to the market and legisaltion is needed in this area to address the issues in a consistent way.
Option 1
Fully harmonise all arrangements in local markets.
This option would see all arrangements harmonised, including gate opening times, gate
closing times, products to be offered, whether markets are exclusive, and mandatory
continuous trading rather than auctions. Gate closure time would be established as close to
real time as possible, to provide maximum opportunity for the market to balance its
positions before it became the TSO responsibility. Markets would be exclusive
i.e. no
bilateral trading
and power exchanges would be obliged to offer small products, in size
and duration
likely a minimum of 0.1MWh in 15 minute blocks. Demand response
would be able to participate in all markets.
Given the difference in technical characteristics of different markets (i.e. some have very
limited internal congestion so very short gate closure times are technically feasible, whilst
others need more time to take remedial actions), this option would likely see some markets
becoming larger (with gate closure times closer to real time) and some smaller (with gate
closure times having to move further away from real time, depending on the precise time
chosen). It would also mean that products would not necessarily reflect the difference in
national systems.
Given the technicalities of this option, it would likely be developed through implementing
legislation.
46
Section 7.3.2 of the Evaluation
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Option 2 - Selected harmonisation, with additional flexibility
This option would introduce standardisation of gate closure time and products in a more
flexible way, specifically allowing some flexibility in national markets to reflect their
differentiated nature. In particular, under this option, legislation would specify:
-
that intraday gate closure time in national markets must not be longer than the cross-
border intraday gate closure time. This would ensure that national markets are not
'taken out of the picture' before the cross-border markets close, and would, in effect,
mean that at a minimum market participants are allowed to trade as close as one hour
ahead of real time.
that power exchanges must offer products that reflect the imbalance settlement period.
This will ensure that market participants are able to trade at a frequency which allows
them to stay in balance.
that barriers to demand response participating in intraday markets must be minimised
specifically, minimum bid size should allow for participation and there should be no
administrative barriers put in place.
-
-
This option would also see more principles added to legislation, with the aim of progressive
harmonisation over time on those design features not touched.
Comparison of the options
Option 0 (Business as usual) would keep the
status quo
and leave intraday markets to
evolve within Member States, with no guarantees they would develop along the same lines,
except in some areas that existing legislation touches (for example, on minimum and
maximum bid prices). There would likely be an impact as a result of the implementation
of market coupling in the intraday time-frame. With significant differences, there is a risk
that liquidity is split and benefits of short-term markets to the integration of RES E and
demand response muted.
Option 1
full harmonisation
would likely see significant changes in a number of
markets. It would involve selecting a gate closure time and applying that to all national
markets. Whilst the precise timing could vary, it would mean that some countries would
need to keep their markets open longer, and some would need to close their markets earlier
than they currently do (notably in Belgium and the Netherlands, where trades can currently
take place up to 5 minutes prior to delivery)
harmonising gate closure times to that of the
shortest in Europe would likely be unachievable for many Member States, particularly
larger ones where the TSO requires more time between knowing the market results and
real time in order to solve internal congestion (the market is blind to congestion within a
bidding zone).
This option would also involve harmonising other aspects, as detailed above. Power
exchanges can be seen as the conduit for energy trades across borders so harmonising the
rules on which trading takes place will minimise differences between national markets and
with the common cross-border market. By increasing the arbitrage opportunities across
these markets, the risk of splitting liquidity is reduced.
On the surface, this might seem like an appropriate response akin to other single market
measures that harmonise standards so that they can be traded within the EU with minimal
barriers. However, in reality this is likely to be much more complex. A significant amount
of the process is IT-driven, and the arrangements have not yet been put in place
it would
therefore be very difficult to determine what the local arrangements should be. Further,
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there is a lack of evidence that such harmonisation would indeed lead to more cross-border
trade
the costs associated with changing IT could be significant with little benefit.
Given that the common cross-border market will likely be more complex (e.g. given the
number of variables, Member States, the fact that calculations will need to consider
available cross-border capacity) in the immediate future this market, and the IT
infrastructure that supports it, may not be able to accommodate the more granular market
arrangements that exist in some Member States. As such, moving all national markets to
the same design details of that of the cross-border market could entail some having to
reduce their granularity, move gate closure time further away from real-time, etc. This
would not fit with the objectives of the present proposal, which aims for increased
flexibility.
Option 2, however, would provide a much more proportionate response. Rather than
specifying a value for the gate closure time in local markets it would specify that it should
be no longer than the cross-border gate closure time. It will provide more opportunity for
arbitrage between markets. It will also move gate closure times closer to real-time in many
markets, which will provide more opportunities for RES E to balance themselves and
demand response to participate in the market, without forcing those markets which already
apply very short-term trading rules to switch to longer timeframes. With regards to
products the markets should be able to accommodate demand-response and small-scale
RES E. It will also leave the most technical characteristics to the implementation of the
CACM Guideline, which has the advantage of allowing specifics to be discussed in detail
with market parties and for more flexibility, i.e. allowing for easy adaptation if and when
requirements need to change.
Whilst this option will not eliminate the risk of splitting liquidity, there is in fact some
evidence that two markets can co-exist and increase overall traded volumes. In a study
looking at the impact of the introduction of an intraday auction for 15 minute products in
Germany
47
, it was found that, whilst the auction pulled some value away from the
continuous intraday market, the total traded volumes increased.
47
"Intraday
Markets for Power: Discretizing the Continuous Trading"
Karsten Neuhoff, Nolan Ritter,
Aymen Salah-Abou-El-Enien and Philippe Vassilopoulos (2016)
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Figure 3: Volumes on the 15mn intraday market and the share of quarters in total
trading volumes (quarters+hours), EPEX (DE)
Source: Neuhoff et al (2016)
The option will also provide a good starting point for progressively harmonising with the
longer-term aim of
one, common intraday market with local specificities minimised to
situations where they are justified due to local differences.
Specific impacts relating to changes in short-term markets are discussed in Section 6.1.3.
With regards to intraday, the results of the modelling indicate positive impacts of
harmonising intraday arrangements in Europe, specifically allowing for the further
reduction of RES E curtailment and lesser use of replacement reserves by 460 GWh and
95 GWh, respectively
Subsidiarity
Given that the EU energy system is highly integrated, prices in one country can have a
significant effect on prices in another, as can arrangements in local markets. Differences
in the operation of local markets can present a barrier to the cross-border trade of energy,
and continuing differences between local markets, and between local markets and the
single cross-border market, risks splitting liquidty and constraining the benefits of a
common cross-border market This will impact on liquidity and the amount of trading
which can take place, as well as erode the benefits of competition and a larger market place
in which energy can be bought and sold.
EU-level action is, therefore, necessary to ensure that the national markets are comparable,
that they enable maximum cross-border trading to happen, and facilitate liquidity as much
as possible. .
There is also a critical link with the CACM Guideline, which establishes principles and
required further methodologies for the operation of intraday markets in the cross-border
context, as well as a link with the upcoming Balancing Guideline. EU-level action is
required to ensure that trading in local markets can reap maximum benefits of the cross-
border solution under development.
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Stakeholders' opinions
Most stakeholders agree on the importance of liquid short-term markets, particularly
intraday and balancing, to the efficient operation of the internal electricity market. They
are, in general, seen as a critical part of ensuring that RES E can be propely intergrated,
notably allowing renewable generators to trade closer to real-term, as well as to stimulating
investment in sources of flexibility such as demand response. Most call for speedy
implementation of common cross-border intraday trading (market coupling) via the XBID
project, whilst recognising the progress that has already been made in day-ahead market
coupling.
Wind Europe calls upon the EU to "ensure
continuous intraday trading with harmonised
gate closure times closer to real time; complementary auctions may be introduced to
increase liquidity".
They argue that "implementing
well-functioning intraday markets
across borders with gate-closure close to real-time will 1) provide renewable producers
with opportunities to adjust their schedule in case of forecasts errors, 2) smooth out the
variability induced by renewable in-feed over broader geographical areas"
48
.
In their publication
"Electricity Market Design: fit for the low-carbon transmision",
Eurelectric state:
"The development of robust cross-border intraday and balancing markets will be crucial
to ensure that the system remains balanced as the share of renewables continues to grow.
It is therefore necessary to promote a liquid continuous implicit cross-border intraday
market with harmonised products in all member states, while capacity pricing shall not
drain liquidity nor reduce the speed of market processes. The market shall be enabled to
determine the most economic dispatch until a gate closure set as close to real-time as
possible (e.g. 15 minutes). TSOs shall only perform the residual balancing of the system."
49
SolarPower Europe state
"progress is needed in particular with a view to achieving better
liquidity and integration of intraday and balancing markets. These short-term markets are
crucial as variable renewable energy sources take a more important role in the power mix.
Products and services should be re-defined to improve the granularity of these markets
and enable the sale of different system services that solar power and other renewables, but
also storage and demand participation can provide."
50
ENTSO-E make the point that
"Accurate short-term market price formation is needed to
reveal the value of flexibility in general and of DSR specifically"
51
and ACER/CEER that
"it
is imperative that everything is done to make sure that price signals reflect scarcity and
to create shorter-term markets which will reward those who provide the flexibility services
which the system increasingly needs."
Further, they state that
"the intraday and balancing
markets will be increasingly important to valuing flexibility and there needs to be a push
48
49
50
51
"A market design fit for renewables".
Wind Europe submission of 27 June 2016
"Electricity Market Design: fit for the low-carbon transmision".
Eurelectirc 2016, available at
http://www.eurelectric.org/media/272634/electricity_market_design_fit_for_low-carbon_transition-
2016-2200-0004-01-e.pdf
"Creating a competitive market beyond subsidies"
July 2015,
Market Design of Demand Side Response"
Policy Paper, November 2015
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to deliver the cross-border intraday (XBID) project and to implement the Network Code
on Electricity Balancing as soon as possible."
52
The March 2016 Electricity Regulatory Forum (the "Florence Forum"), a forum for
stakeholders to engage on wholesale market regulatory issues, made the following relevant
conclusion:
"The Forum acknowledges that, whilst cross-border day-ahead and intraday markets will
see significant harmonisation as part of the implementation of the Capacity Allocation and
Congestion Management guideline, there is significant scope for ensuring that national
markets are appropriately designed to accommodate increasing proportions of variable
generation. In particular, the Forum invites the Commission to identify those aspects of
national intraday markets that would benefit from consistency across the EU, for example
on within-zone gate closure time and products that should be offered to the market. It also
requests for action to increase transparency in the calculation of cross-zonal capacity,
with a view to maximising use of existing capacity and avoiding undue limitation and
curtailment of cross-border capacity for the purposes of solving internal congestions."
52
Joint ACER-CEER
response to European Commission’s Consultation on a new Energy Market Design,
October 2015
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2.3. Improving the coordination of Transmission System Operation
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Summary table
Objective: Stronger coordination of Transmission System Operation at a regional level
Option 0
BAU
Limit the TSO coordination efforts to the
implementation of the new Guideline on
Transmission System Operation (voted at the
Electricity Cross Border Committee in May
2016 and to be adopted by end-2016) which
mandates the creation of Regional Security
Coordinators (RSCs) covering the whole
Europe to perform five relevant tasks at regional
level as a service provider to national TSOs.
Lowest political resistance.
Option 1
Enhance the current set up of existing RSC by
creating Regional Operational Centers (ROCs),
centralising some additional functions at regional
level over relevant geographical areas and
delineating competences between ROCs and
national TSOs.
Option 2
Go beyond the establishment of ROCs
that coexist with national TSOs and
consider the creation of Regional
Independent System Operators that can
fully take over system operation at
regional level. Transmission ownership
would remain in the hands of national
TSOs.
Option 3
Create
a
European-wide
Independent System Operator
that can take over system
operation at EU-wide level.
Transmission ownership would
remain in the hands of national
TSOs.
Description
Suboptimal in the medium and long-term.
Most suitable: Most suitable option(s): Option 1
(Option 2 and Option 3 constitute the long-term vision)
Cons
Enlarged scope of functions assuming those tasks
where centralization at regional level could bring
benefits
A limited number (5 max) of well-defined regions,
covering the whole EU, based on the grid topology
that can play an effective coordination role. One
ROC will perform all functions for a given region.
Enhanced cooperative decsion-making with a
possibility to entrust ROCs with decision making
competences on a number of issues.
Could find political resistance towards
regionalisation. If key elements/geography are not
clearly enshrined in legislation, it might lead to a
suboptimal outcome closer to Option 0.
Pros
Improved system and market operation
leading to optimal results including
optimized infrastructure development,
market facilitation and use of existing
infrastructure, secure real time operation.
Seamless and efficient system
and market operation.
Politically challenging. While this option
would ultimately lead to an enhanced
system operation and might not be
discarded in the future, it is not
considered proportionate at this stage to
move directly to this option.
Extremely
challenging
politically. The implications of
such an option would need to be
carefully
assessed.
It
is
questionable whether, at least at
this stage, it would be
proportionate to take this step.
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Detailed description of the baseline
Operation of the transmission system
Traditionally, prior to the restructuring of the energy sector, most electricity utilities were
run by national and very often state-owned monopolies. These were in most cases
vertically integrated utilities that owned and operated all the generation and system assets
in their allocated territories.
The adoption and implementation of the three energy packages have led to the introduction
of competition in the generation and supply of electricity, the introduction of wholesale
electricity markets for the trading of electricity as well as to different degrees of unbundling
of transmission and distribution activities, which constitute monopoly activities.
Figure 1. The electricity value chain
generation
Erzeugung
trading
Handel
transmission
Übertragung
distribution
Verteilung
Vertrieb
supply
competitive activity
competitive activity
Source: European Commission
regulierter Bereich
monopoly activity
The fact that the activity of electricity transmission system operation is mostly national in
scope derives from the past existence of vertically integrated utilities that were active
throughout the whole electricity supply value chain. Following the restructuring of the
electricity sector, Member States naturally tasked TSOs with the responsibility of ensuring
the secure operation of the electricity system at national level.
This approach is currently reflected in the EU legislation. Article 12 of the Electricity
Directive establishes that each TSO shall be responsible,
inter alia,
for managing the
electricity flows on the system, taking into account exchanges with other interconnected
systems. The Commission Implementing Regulation establishing a guideline on electricity
transmission system operation ('System Operation Guideline') specifies further this
obligation and sets out a requirement on TSOs to ensure that their transmission system
remains in the normal state and makes them responsible for managing violations of
operational security
53
.
Coordination of transmission system operation: shift from a voluntary approach to a
mandatory framework
Driven by the lessons learnt from the serious electrical power disruption in Europe in 2006,
European TSOs have pursued enhancing further regional cooperation and coordination. To
this end, TSOs voluntarily launched Regional Security Coordination Initiatives (RSCIs),
53
The System Operation Guideline was voted on 4 May 2016 and is due to be adopted after scrutiny by
the Council and the European Parliament.
https://ec.europa.eu/energy/sites/ener/files/documents/SystemOperationGuideline%20final%28provisi
onal%2904052016.pdf
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entities covering a greater part of the European interconnected networks aiming at
improving TSO cooperation. The main RSCIs in Europe are Coreso and TSC, both
launched in 2008, followed by the ongoing development and establishment of additional
RSCIs, such as SCC in Belgrade (launched in 2015) and an RSCI to be launched by Nordic
TSOs by the end of 2017. Currently, RSCIs monitor the operational security of the
transmission system in the region where the TSOs with membership in the RSCIs are
established and assist TSOs proactively in ensuring security of supply at a regional level.
By performing these functions, RSCIs provide TSOs with detailed forecasts of security
analysis and may propose coordinated measures that TSOs may decide or not to
implement.
In December 2015, all European TSOs except for SEPS a.s., the Slovakian TSO, signed a
multi-lateral agreement to roll out RSCIs in Europe and to have them deliver core services
to support the TSOs carry out their functions and responsibilities at national level.
R&D results:
Tools for TSOs to deal with an increase in cross-border flows and variability
of generation are being developed in European projects like ITESLA and UMBRELLA.
They show that coordinated operational planning of power transmission systems is
necessary to cope with increased uncertainties and variability of (cross-border) electricity
flows. These tools help decrease redispatching costs and the available cross-border
capacity and flexibility while ensuring a high level of operational security.
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Figure 2 State of play of the voluntary membership of TSOs in RSCIs across the
European Union.
Source: European Commission (June 2016)
The voluntary establishment of RSCIs has been widely recognised as a positive step
forward for the enhancement of cooperation of transmission system operation and has been
recently formalised in EU legislation with the new System Operation Guideline.
Building on the emerging regional initiatives, the System Operation Guideline takes a
further step and mandates the cooperation of EU TSOs at regional level through the
establishment of maximum six regional security coordinators (RSCs) which will cover the
whole EU to perform a number of relevant tasks at regional level as service providers to
national TSOs.
The tasks that RSCs will perform pursuant to the System Operation Guideline are: (i)
regional operational security coordination; (ii) building of the common grid model; (iii)
regional outage coordination; and (iv) regional adequacy assessment. The task of capacity
calculation follows from the implementation of the CACM Guideline and is not assigned
in the System Operation Guideline. The draft Commission Regulation establishing a
network code on Emergency and Restoration intends to extend the tasks of RSCs to include
a consistency assessment of the TSOs' system defence plans and restoration plans.
The framework set out in the System Operation Guideline is meant to build on the existing
voluntary initiatives of TSOs (Coreso and TSC). It requires each TSO to join a RSC and
allows a degree of flexibility to TSOs to organise the coordination of regional system
operation. In this regard, the TSOs of the different capacity calculation regions will have
the freedom to appoint more than one RSC for that region and to allocate the tasks, as they
deem most efficient, between them.
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Based on the deadlines for implementation envisaged in the System Operation Guideline,
RSCs should be fully operational around mid-2019.
Box 1: Support functions to be carried out by RSCs under the network codes and
guidelines
Common grid model:
The common grid model provides an EU-wide forecasted view of all major grid assets
(generation, consumption, transmission) updated every hour. RSCs will participate in the iterative process
starting from the collection of individual grid models prepared and shared by TSOs and aiming at delivering
to all RSCs and TSOs, a common grid model adequate for the other functions listed below. This function is
required at least for timeframes from year-ahead to intraday (year-ahead, week-ahead, day-ahead, and
intraday).
Operational planning security analysis:
RSCs will identify risks of operational security in any part of their
regional area (mainly triggered by cross-border interdependencies). They will also identify the most efficient
remedial actions (i.e., actions implemented by TSOs aimed at maintaining or returning the electricity system
to the normal system state) in these areas and recommend them to the concerned TSOs, without being
constraint by national borders. This function covers at least the day-ahead and intraday timeframes.
Coordinated capacity calculation:
RSCs will calculate the available electricity transfer capacity across
borders, using flow-based (FB) or net transfer capacity (NTC) methodologies. These methodologies aim at
optimising cross-border capacities while ensuring security of supply. This function is carried out at least on
the D-2 (for day-ahead capacity allocation) and D-1/ intraday (for intraday capacity allocation) timeframes.
Short and very short-term adequacy forecasts:
RSCs will provide TSOs with consumption, production
and grid status forecasts from the day-ahead up to the week-ahead timeframe. In particular, RSCs will
perform a regional check/update of short/medium term active power adequacy, in line with agreed ENTSO-
E methodologies, for timeframes shorter than seasonal outlooks. This function is carried out week-ahead
(until day-ahead only if scarcity is detected or if there are changes in relevant hypotheses compared to week-
ahead).
Outage planning coordination:
This function consists in creating a single register for all planned outages
of grid assets (overhead lines, generators, etc.). RSCs will identify outage incompatibilities between relevant
assets whose availability status has cross-border impact and limit the pan-European consequences of
necessary outages in grid and electricity production by coordinating planning outages. RSCs will carry out
this function in the year-ahead timeframe with updates up to week-ahead (on TSO requests).
Consistency assessment of the TSOs' system defence plans and restoration plans:
RSCs will assist TSOs
in ensuring the consistency of the system defence plans and restoration plan.
Deficiencies of the current legislation
The regional TSO cooperation model resulting from the adoption of electricity network
codes and guidelines constitutes a positive development compared to the existing voluntary
cooperation. However, as explained below, this step, while being effective in the short-
term, is not sufficient in the medium and long-term.
The unprecedented changes concerning the integration of the European electricity markets
and the European agenda for a strong decarbonisation of the energy sector, resulting in
increasingly higher shares of decentralized and often intermittent renewable energy
sources, have made the operation of the national electricity systems much more interrelated
than in the past.
The recently voted System Operation Guideline has not entered into force and been
implemented yet. Nonetheless, as highlighted in pp 32-33 of the Evaluation, the challenges
the EU power system will be facing in the medium to long-term are pan-European and
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cannot be addressed and optimally managed by individual TSOs, rendering the current
legal framework concerning system operation not adapted to the reality of the dynamic and
intermittent nature of the future electricity system and putting into question whether the
mandated cooperation of TSOs via RSCs is fit for purpose in the post 2020 context.
First, the functions envisaged for RSCs in the System Operation and in the CACM
Guideline will not suffice in the medium to long-term as there is an increasing need for
electricity systems to be operated on a regional basis. Furthermore, there is room to enlarge
the scope of functions that would increase the efficiency of the overall system, if performed
at regional level.
Second, the geographical scope of RSCs set out in the System Operation Guideline could
not be efficient in the post 2020 context. RSCIs have grown organically with political
considerations in mind, rather than following criteria solely based on the technical
operation of the grid. The degree of flexibility envisaged in the System Operation
Guideline will allow TSOs to maintain that
status quo,
undermining the goal of having a
regional entity that oversees system and market operation in the region.
Figure 2
representing the current membership of TSOs in RSCIs across the Union reflects this
situation (e.g., membership of TenneT NL, the TSO of the Netherlands, in TSC as opposed
to Coreso). The coordination with other regional groupings of TSOs deriving from the
implementation of other network codes and guidelines is also an issue. For example, given
the degree to which the grid is meshed in the CWE and CEE regions, it is virtually
impossible to draw permanent lines dividing the regions and still respect the electrical
interdependencies. Hence, the presence of two RSCIs (Coreso and TSC) for this region
does not seem the optimal solution to play an effective coordination role.
Third, the implementation of the System Operation Guideline will entail that RSCs will
play an increasingly important support role for TSOs. However, the full decision-making
responsibility will remain with TSOs who will have to do the grid planning while taking
into consideration also new options to grid extensions (such as energy storage). RSCs will
not have executive powers and their activities will be limited to providing planning
services to individual TSOs, who can accept or reject those services and who will retail
full control of and accountability for the planning and operation of their individual
networks. For example, when deciding about the commercial cross-border capacities in a
given region which are already calculated at regional level, the decision taken by RSCs are
non-binding meaning that they can be considered as an input that can be changed by TSOs
based on national interest (e.g. in case of scarcity of supply in one country the TSO might
be tempted to reduce their export capacities but this might not be the best decision from a
regional system security perspective) or due to constraints in the national legal framework.
In this regard, the rejection of a recommendation by a TSO would suffice to put in question
the overall set of recommendations issued by a RSC. For example, if in a recommendation
for an optimal set of remedial actions a given TSO did not agree, this would imply the
whole recalculation of remedial actions for the region since such measures are usually
interdependent. There is additional evidence pointing out to this problem. The ACER
market monitoring report 2015 (to be published in 2016) remarks that there are strong
indications that during the capacity calculation process TSOs resort to unequally treating
internal and cross-zonal flows on their networks.
To conclude, while the enhanced regional TSO cooperation resulting from the adoption of
electricity network codes and guidelines constitutes a positive step forward, it is important
to note that it will not allow realising the full potential of these regional entities in the
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medium to long-term. If the benefits of market integration are to be fully realised, TSOs
will have to cooperate even more closely at regional level. This will require adjusting the
way in which the operation of the electricity system will be managed under the System
Operation Guideline.
Presentation of the options
Option 0 - BAU
Option 0 would be to stop the coordination efforts at this stage and limit it to the progress
achieved with the implementation of the System Operation Guideline.
The upcoming RSCs will have the following features:
i.
Functions. Five main functions
54
will be performed by the upcoming RSCs as
service providers to national TSOs under the network codes and guidelines (see
Box 1
above for a more detailed explanation of each of these functions).
a. Coordinated Security Analysis (including Remedial Actions-related
analysis)
b. Common Grid Model Delivery
c. Outage Planning Coordination
d. Short and Very Short Term Resource Adequacy Forecasts
e. Coordinated Capacity Calculation
The addition of new functions would mainly depend on the voluntary initiative of
TSOs, which in some instances could lead to inefficient outcomes given that they
would not always have the "regional" perspective in mind but rather their own
interest, particularly given the flexibility at the time of defining the geographical
scope.
Geographic scope. While RSCs will give full coverage across the EU, the size and
composition of the regions where they will be established may not always be
defined having the technical operation of the grid in mind. Business and political
criteria could also play a role. In particular, TSOs in a region would continue having
flexibility to decide which RSC provides a given service (including new ones
developed voluntarily) to that region. This would allow a given region to get
services from different RSCs. While this has been accepted as a valid compromise
in the short-term, it undermines the goal of having a regional entity with enhanced
overview over system and market operation in the region.
ii.
Decision-making responsibilities. The upcoming RSCs will not have any decision-
making powers but a purely advisory role. The responsibility for system operation
will remain with TSOs at national level. The fact that RSCs issue recommendations
means that ultimately an individual TSO may be constrained by the national
framework and reject the implementation of such recommendation, against the
interest of all the other TSOs of the region. Hence, the set up of the RSC being able
54
Six functions with the adoption of the Emergency and Restoration network code
('Consistency
assessment of TSOs' system defence plans and restoration plans').
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to provide an added value at regional level would be compromised. For example,
as described above, if in a recommendation for an optimal set of remedial actions
a given TSO did not agree, this would imply the whole recalculation of remedial
actions for the region since these measures are usually interdependent.
iii.
Institutional layout/governance. The interaction between the RSCs, NRAs, TSOs,
ACER and ENTSO-E would remain as set out in the System Operation Guideline.
Essentially, TSOs and NRAs would continue to be responsible for the direct
implementation and oversight of RSCs at national level. ACER and ENTSO-E
would remain responsible for ensuring the cooperation of NRAs and TSOs at EU
level, respectively.
Option 0+: Non-regulatory approach
Stronger enforcement would not suffice to address the needs of the electricity system
regarding stronger TSO cooperation at regional level.. As in option 0, any progress beyond
the framework in the System Operation Guideline and the application of other network
codes would depend on the voluntary initiatives of TSOs. However, the voluntary
initiatives would be limited due to the constraints resulting from differing legislation at
national level. Hence, stronger enforcement or a voluntary approach is not a possible
option.
Option 1: Enhance the current set up of existing RSCs by creating ROCs, centralising some
additional functions over relevant geographical areas and optimising competences between
ROCs and national TSOs
Option 1 would aim at enhancing the current set up of existing RSCs by creating ROCs.
ROCs are not meant to substitute TSOs but to complement their role at regional level. This
option would set out a number of basic elements in legislation but allow flexibility to
TSOs to work out the details on how the ROCs will function and perform their tasks. ROCs
will present the the following features:
i.
Functions. Enlarged scope of functions, assuming new tasks where centralization
at regional level could bring benefits. These functions would not cover real time
operation which would be left solely in the hands of national TSOs. In addition to
the functions emanating from existing network codes and guidelines (see
Box 1),
these functions would be:
a. Solidarity in crisis situations: Management of generation shortages;
Supporting the coordination and optimisation of regional restoration
b. Sizing and procurement of balancing reserves
c. Transparency: Post-operation and post-disturbances analysis and reporting;
Optimisation of TSO-TSO compensation mechanisms
d. Risk-preparedness plans (if delegated by ENTSO-E)
e. Training and certification (if delegated by ENTSO-E)
ii.
Geographic scope. A limited number of well-defined regions, covering the whole
EU. TSOs establishing the ROCs will need to decide the scope of these regions
based on technical criteria (e.g. grid topology) to ensure that they can play an
effective coordination role. In contrast to what is currently in the System Operation
Guideline, each ROC would perform all functions for a given region. Larger
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regions could include, if necessary, back-up centres and/or sub regional desks when
for example some functions would require specific knowledge of smaller portions
of the grid.
iii.
Cooperative decision-making. ROCs would have an enhanced advisory role for all
functions. In order to respect to the maximum possible extent the regional
recommendations, TSOs should transparently explain when and why they reject
the recommendation of the ROC. Given that a role limited to issuing
recommendations may lead to sub-optimal results as regards the performance of
some of the functions
55
, decision-making powers could be entrusted to ROCs for
a number of relevant issues (i.e., remedial actions, capacity calculation) either
directly by a Regulation or subsquentely by mutual agreement of the NRAs or
Member States overseeing a certain ROC. By optimising decision-making
responsibilities between ROCs and national TSOs the seamless system operation
between the ROCs and the TSOs would be ensured.
Institutional layout/governance. Enhanced cooperation between TSOs would be
accompanied by an increased level of cooperation between regulators and
governments as well as by an increased oversight from ACER and ENTSO-E.
iv.
55
This sub-optimal situation would derive from the fact that the rejection by a single TSO of the
recommendation issued by the ROC would put in question the overall set of recommendations.
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Box 2: Additional functions performed by ROCs under Option 1
-
Solidarity in crisis situations:
-
Management of generation shortages.
ROCs would optimise the generation park in a region while
attempting
to increase transmission capacity to the Member State which suffers generation
shortage. The aim of this function is to avoid load cuts (energy non served situations) in a country
while other countries still optimise the market and/or enjoy high generation margins.
-
Supporting the coordination and optimisation of regional restoration.
ROCs would recommend the
regional necessities during restoration (e.g., resynchronisation sequence of large islands in case of
the split of a synchronous area).
Sizing and procurement of balancing reserves:
-
Regional calculation of daily balancing reserves.
ROCs would carry out regional sizing of daily
balancing reserves (disregarding political borders and considering only technical limitations related
to geographical dispersion of reserves) on the basis of common probabilistic methodologies (i.e.
balancing reserve needs based on different variables such as RES generation forecast, load
fluctuations and outage statistics).
-
Regional procurement of balancing reserves.
ROCs would create regional platforms for the
procurement of balancing reserves, complementing the regional sizing of balancing reserves.
Transparency:
-
Post operation and post disturbances analyses and reporting.
ROCs would carry out centralised
post-operations analyses and reporting, going beyond the existing ENTSO-E Incidents
Classification Scale (ICS).
-
Optimisation of TSO-TSO compensation mechanisms.
ROCs would administer common money
flows among TSOs, such as Inter-TSO Compensation (ITC), congestion rent sharing, re-dispatching
cost sharing, cross-border cost allocation (CBCA). Furthermore, ROCs should propose
improvements to the schemes based on technical criteria and aiming for the optimal overall
incentives.
Risk-preparedness plans.
If delegated by ENTSO-E, the ROCs' function would be to identify the
relevant risk scenarios in its region that the risk preparedness plans should cover. Based on ROCs'
proposals, Member States would develop the plans. ROCs could organise crisis simulations (stress
tests) together with Member States and other relevant stakeholders. During such crisis simulations the
plans would be tested to check if they are suited to address the identified cross-border or regional crisis
scenarios.
Medium term adequacy assessments:
if delegated by ENTSO-E, ROCs would complement the
ENTSO-E seasonal outlooks with adequacy assessments carried out in a regional context where
possible crisis scenarios (e.g. prolonged cold spell), including simultaneous crisis, should be identified
and simulated.
Training and certification.
The network code on staff training and certification as foreseen in the
ACER framework guideline on system operation is still pending. ROCs could cover functions related
to trainings between TSOs as well as centralise of some trainings in issues related to cross-border
system operation. Further, this function should allow regional training on simulators (IT system based
on a relevant representation of the system, including networks, generation and load).
-
-
-
-
-
Option 2: Creation of Regional Independent System Operators
Option 2 would be to go beyond the establishment of ROCs that coexist with national
TSOs and consider the creation of Regional Independent System Operators (RISOs) that
can fully take over system operation at regional level.
RISOs would have the following features:
i.
Functions. RISOs would have an enlarged scope of functions compared to ROCs.
In addition to the functions under Option 1, RISOs would also be responsible for
real time operation of the electricity system (e.g., operation of real time balancing
markets) and for infrastructure planning. Infrastructure related functions could
include for example the identification of the transmission capacity needs:
proposing priorities for network investments based on the long-term resource
adequacy assessment, the situation in the interconnected system and identified
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structural congestions, while considering an interconnected system without
political borders.
ii.
iii.
Geographic scope. The scope of RISOs would be the same as for ROCs.
Decision-making responsibilities. All system operation functions would be
performed by the RISOs, which would have decision-making powers. Existing
TSOs would remain as transmission owners and solely operate physically the
transmission assets and provide technical support to RISOs (e.g., collection and
sharing of data).
Institutional layout/Governance. Additional changes in the institutional framework
would be required to enable the RISO approach. For example, it would be
necessary to amend the powers and competences of TSOs, of regulatory authorities
and of ACER in order to ensure the appropriate oversight of these entities. It would
also be necessary to consider aspects such as the financing of RISOs or the
applicability of unbundling rules.
iv.
Option 3: creation of a European-wide Independent System Operator
Option 3 would imply the creation of a European-wide Independent System Operation (EU
ISO) that would take over system operation at EU-wide level.
This entity would have the following features:
i.
ii.
iii.
Functions. The functions would be the same as those proposed under Option 2 for
RISOs.
Geographic scope. The EU ISO would be responsible for system operation at EU-
wide level.
Decision-making responsibilities: The EU ISO would perform all system operation
functions and hence would have decision-making powers. TSOs would solely
operate physically the transmission assets and provide technical support to RISOs
(e.g., collection and sharing of data).
Institutional layout/Governance: significant changes would be required in the
institutional framework to enable the creation of an EU ISO and an effective
oversight of its acitivities. It would be necessary to amend the powers and
competences of TSOs, of regulatory authorities and of ACER. It would also be
necessary to consider aspects such as its financing, monitoring of its performance,
etc.
iv.
Comparison of the options
The following Section provides a comparison of the options described above based on the
four main elements identified: (i) functions; (ii) geographical scope; (iii) decision-making
competences; and (iv) institutional layout/ governance. Given that only a few studies have
been carried out on this field, the assessment of the options will be mainly qualitative,
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based on the feedback received from stakeholders and on the content of the studies
published to date, and providing figures where they exist.
(i)
Functions
It is not possible to provide a complete quantification of the costs and benefits of each of
the Options as regards the set of functions to be performed at regional or EU level given
that few studies have assessed these costs and benefits. However, the insights from several
previous studies cover the potential benefits of a supranational approach to system
operation.
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Table 1 Functions that would be covered under each of the options
RSCs
(Option
0)
ROCs
(Option
1)
RISOs/EU
ISO
(Options 2
and 3)
System Operation
Coordinated Security Analysis (including Remedial Actions-
related analysis)
Common Grid Model Delivery
Outage Planning Coordination
Short and Medium Term Resource Adequacy Forecasts
Regional system defence and restoration plans
Centralised post operation analyses and reporting
Training and certification
Market Related
Coordinated Capacity Calculation
Coordinated sizing and procurement of balancing reserves
Network Planning
Identification of the transmission capacity needs
Technical and economic assessment of CBCA cases
Administration of TSO-TSO compensation mechanisms (ITC,
congestion rent sharing, redispatching cost sharing, CBCA)
Risk-preparedness
Support Member States on development of risk preparedness
plans
Source: DG ENER
x
x
x
x
x
x
56
x
x
x
x
x
x
x
58
x
x
x
x
x
x
x
x
x
x
x
57
x
x
x
x
x
x
56
57
58
It could include decision-making powers.
The CACM Guideline provides for regional capacity calculators. However, following the commitments
of ENTSO-E, this role could be already assumed for RSCs.
It could include decision-making powers.
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Table 2 Qualitative estimate of the economic impact of the Options:
Option 0:
RSC
approach
Option 1:
ROC
approach
Option 2:
RISO
approach
Option 3:
EU
ISO approach
Economic Impact
Enhancing security of supply by
minimising the risk of blackouts
59
60
0/+
+
++
++
Lowering costs through increased
efficiency in system operation
61 62
63
0/+
++
+++
+++
Maximising transmission capacity
offered to the market
64
Reducing the need of remedial
actions by coordinating and
activating in a coordinated way
redispatching
65 66
Minimising the costs of balancing
provision by taking a more
coordinated approach towards the
sizing of balancing reserves
67 68 69
Optimisation
planning
70
of
infrastructure
0/+
++
+++
+++
0/+
++
+++
+++
0/+
++
+++
+++
0
0
++
+++
Enhancing transparency
71
0
0/+
+
+
Costs of implementation72
0/-
-
---
----
Other impacts
Administrative
governance
impacts/
0/-
-
--
---
Source: DG ENER.The assumptions in this table are based on the studies existing in this field as well as on
the feedback received from stakeholders in their response to the public consultation and from estimations
concerning the resources of RSCs and ENTSO-E.
In sum, as illustrated in Table 2, the set of functions in
Option 0
will entail limited costs
and benefits, since many of these functions are already carried out by RSCIs in their
supporting role to TSOs. The implementation of the System Operation Guideline and
establishment of ROCs will not involve significant changes to the
status quo.
The set of
additional functions under
Option 1
will entail efficiency gains and increase social welfare
that will derive from providing additional functions to ROCs to be optimised at regional
level (as opposed to national level)
73
. In addition, it will entail costs related to the shift of
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59
60
61
62
63
64
65
66
67
68
69
The financial and social impact of wide area security breaches is enormous: as estimated by ENTSO-E,
the economic impact of wide area security breaches could be really important; the cost of a 20 GW load
disconnection during a large brownout is estimated to 800 million euros per hour (i. e. 40 euros / kWh).
Blackouts have an even higher impact. This provides quantified insight into the importance of optimised
emergency and restoration efforts with a central coordination of locally required efforts.
ENTSO-E (2014), "Policy
Paper on Future TSO Coordination for Europe",
Retrieved from:
https://www.entsoe.eu/Documents/Publications/Position%20papers%20and%20reports/141119_ENTS
O-E_Policy_Paper_Future_TSO_Coordination_for_Europe.pdf
The management of generation shortages should increase the regional social welfare as a result of a
decrease of financial losses that would otherwise result from disconnection of load. It would also
increase solidarity and promote trust in the internal energy market.
Also, some of the benefits will derive from the optimisation of training and certification. TSOs will gain
more practical experiences using same tools, practicing common scenarios and sharing best practices.
This should lead to faster system restoration and more efficient tackling of regional-wide system events.
A regional approach to adequacy assessment enhances the use of cross-border connections at critical
moments, resulting in an overall less required generating capacity in Europe. The enhancement is
expected to increase with increasing variable renewable energy in the system. The IEA mentions a
benefit of 1.4 euros/MWh based on the study of Booz & co. An example for regional adequacy
assessment is provided by the Pentalateral Energy Forum.
A supranational approach (moving local responsibilities to ROCs) to capacity calculation can bring
significant welfare benefits due to more efficient use of infrastructure and the consequent benefits
coming from the improved arbitrage between price zones. The CACM Guideline Impact assessment
estimates the welfare gains of a supranational approach to flow-based capacity calculation to be in the
region of 200-600 million euros per year. These benefits would only partially materialise (20% of
welfare gains would not be realised) on a voluntary basis, leaving significant parts of the capacities used
in a suboptimal manner.
Significant benefits are expected by the fact that enhanced TSO cooperation minimises the need for
redispatching, especially costly emergency actions. To illustrate, Kunz et al. quantified the benefits of
coordinating congestion management in Germany: in case each TSO is responsible to relief overflows
within its own zone with its own resources, which reflects the current situation in Germany closest,
redispatch costs of 138.2 million euros per year accrue. Coordinating the use of transmission capacities
renders costs of 56.4 million euros per year. As a benchmark, one single unrestricted TSO across all
zones would have to bear redispatch expenditures of 8.7 million euros per year. Kunz et al. also
quantified the benefits of coordinating congestion management cross-border (for the region comprising
Germany, Poland, Czech Republic, Austria, Slovakia): without coordination, total costs of congestion
management amount to 350 million euros per year, they decrease to 70 million euros per year for
optimised congestion management (including remedial actions and flow-based cross-border capacity
allocation).
Kunz et al.,
"Coordinating Cross-Country Congestion Management",
DIW Berlin , 2016 and Kunz et
al.,
"Benefits of Coordinating Congestion Management in Germany",
DIW Berlin, 2013
As regards the regional sizing and procurement of balancing reserves, the added value of this function
is gain in social welfare due to decreased size of needed balancing reserves and gains in techno-economic
optimisation of the procurement of the needed balancing reserves. Shared balancing has cost advantages
residing from netting of imbalances between balancing areas and from shared procurement of balancing
resources or reserves. This can be based on exchanging surpluses or based on a shared or common merit
order for all balancing resources. Mott Macdonald mentions potential overall benefits from allowing
cross-border trading of balancing energy and the exchanging and sharing of balancing reserve services
of the order of 3 billion euros per year and reduced (up to 40% less) requirements for reserve capacity.
This is for a European electricity supply system with roughly 45% renewable energy.
Mott MacDonald (2013), "Impact
Assessment on European Electricity Balancing Market"
Retrieved
from:
https://ec.europa.eu/energy/sites/ener/files/documents/20130610_eu_balancing_master.pdf
According to the study carried out by Artelys on Electricity balancing: market integration & regional
procurement, regional sizing and procurement of reserves by ROCs could lead to benefits of 2.9 billion
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these functions from national to regional level (e.g., development of processes and tools at
regional level) and will have an impact on the institutional structures (i.e., need to adapt
the institutional framework to ensure the proper monitoring of implementation of the
functions).
Option 2
will present additional gains and costs compared to Option 1. The
benefits will result from the more integrated operation of the system at regional level as
well as from the additional set of functions to be performed by RISOs, which will comprise
real-time operation of the electricity system. The costs will derive from the need to develop
new methodologies, processes and tools to ensure the performance of these additional
functions and the need to adapt the current oversight of the performance of these functions.
Option 3
is the option that will entail most economic gains (deriving from the efficiencies
of performance of the functions at EU level) and also most implementation costs.
(ii)
Geographic scope
In the current context of the rolling out of RSCs (Option
0),
there will be certain flexibility
for TSOs to decide which coordinator provides a given service to a region. This could
allow a given region to get services from different providers. While this is an acceptable
compromise in the short and medium term, it partly undermines the goal of having a
regional entity with enhanced overview over system operation and market operation in the
region. In addition, although there will be full European coverage by the RSCs (with a
maximum number of 6), the size and composition of the regions is not always defined
having the technical operation of the grid in mind. Business and political criteria play also
a role in it.
70
71
72
73
Euros (compared to 1.8 billion euros benefits from national sizing and procurement). An EU-wide sizing
and procurement of balancing reserves would lead to benefits of 3.8 billion Euros.
The added value as regards the identification of the transmission capacity needs at regional level is the
provision of neutral, regional view of investments needs. The industry represented by Eurelectric claims
that "Network
investment planning and the coordination of TSOs' network investment decisions by the
RISOs are the next natural steps."
As regards the technical and economic assessment of cross-border
cost allocation (CBCA) cases, benefits are expected from higher efficiency and quicker processes for
important transmission infrastructure projects.
As regards the optimisation of TSO-TSO compensation mechanisms, the added value is increased
transparency and step-by-step optimisation of the schemes, resulting in more cost-efficient operation of
the system. This is supported by Eurelectric which states that
"Regarding coordination of network