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
kom (2016) 0864 - Ingen titel
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
1.1.1. Summary table ................................................................................................................................. 4
1.1.2. Description of the baseline .............................................................................................................. 5
1.1.3. Deficiencies of the current legislation ............................................................................................. 6
1.1.4. Presentation of the options ............................................................................................................. 9
1.1.5. Comparison of the options ............................................................................................................ 11
1.1.6. Subsidiarity..................................................................................................................................... 14
1.1.7. Stakeholders' opinions ................................................................................................................... 14
1.2. Regulatory exemptions from balancing responsibility ...................................................................17
1.2.1. Summary table ............................................................................................................................... 18
1.2.2. Description of the baseline ............................................................................................................ 19
1.2.3. Deficiencies of the current legislation ........................................................................................... 20
1.2.4. Presentation of the options ........................................................................................................... 22
1.2.5. Comparison of the options ............................................................................................................ 24
1.2.6. Subsidiarity..................................................................................................................................... 25
1.2.7. Stakeholders' opinions ................................................................................................................... 26
1.3. RES E access to provision of non-frequency ancillary services ........................................................29
1.3.1. Summary table ............................................................................................................................... 30
1.3.2. Description of the baseline ............................................................................................................ 31
1.3.3. Deficiencies of the current legislation ........................................................................................... 33
1.3.4. Presentation of the options ........................................................................................................... 34
1.3.5. Comparison of the options ............................................................................................................ 35
1.3.6. Subsidiarity..................................................................................................................................... 36
1.3.7. 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
2.1.1. Summary table ............................................................................................................................... 42
2.1.2. Description of the baseline ............................................................................................................ 43
2.1.3. Deficiencies of the current legislation (see also Section 7.4.2 of the evaluation) ......................... 47
2.1.4. Presentation of the options ........................................................................................................... 48
2.1.5. Comparison of the options ............................................................................................................ 49
2.1.6. Subsidiarity..................................................................................................................................... 50
2.1.7. Stakeholders' opinions ................................................................................................................... 50
2.2. Removing distortions for liquid short-term markets ......................................................................53
2.2.1. Summary table ............................................................................................................................... 54
2.2.2. Description of the baseline ............................................................................................................ 55
2.2.3. Deficiencies of the current legislation ........................................................................................... 58
2.2.4. Presentation of the options ........................................................................................................... 59
2.2.5. Comparison of the options ............................................................................................................ 60
2.2.6. Subsidiarity..................................................................................................................................... 62
2.2.7. Stakeholders' opinions ................................................................................................................... 63
2.3. Improving the coordination of Transmission System Operation .....................................................65
2.3.1. Summary table ............................................................................................................................... 66
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2.3.2. Detailed description of the baseline .............................................................................................. 67
2.3.3. Deficiencies of the current legislation ........................................................................................... 70
2.3.4. Presentation of the options ........................................................................................................... 72
2.3.5. Comparison of the options ............................................................................................................ 76
2.3.6. Subsidiarity..................................................................................................................................... 87
2.3.7. Stakeholders' opinions ................................................................................................................... 87
3. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA I, OPTION 1(C);
PULLING DEMAND RESPONSE AND DISTRIBUTED RESOURCES INTO THE
MARKET .................................................................................................................................... 89
3.1. Unlocking demand side response ..................................................................................................91
3.1.1. Summary table ............................................................................................................................... 92
3.1.2. Description of the baseline ............................................................................................................ 93
3.1.2.1. Smart Metering ...................................................................................................................... 93
3.1.2.2. Market arrangements for demand response ......................................................................... 95
3.1.3. Deficiencies of current legislation ................................................................................................ 101
3.1.3.1. Deficiencies of current Smart Metering Legislation ............................................................. 102
3.1.3.2. Deficiencies of current regulation on demand response ..................................................... 103
3.1.4. Presentation of the options ......................................................................................................... 104
3.1.5. Comparison of the options .......................................................................................................... 106
3.1.6. Subsidiarity................................................................................................................................... 125
3.1.7. Stakeholders' opinions ................................................................................................................. 129
3.2. Distribution networks ................................................................................................................. 143
3.2.1. Summary table ............................................................................................................................. 144
3.2.2. Description of the baseline .......................................................................................................... 145
3.2.3. Deficiencies of current legislation ................................................................................................ 150
3.2.4. Presentation of the options ......................................................................................................... 152
3.2.5. Comparison of the options .......................................................................................................... 153
3.2.6. Subsidiarity................................................................................................................................... 157
3.2.7. Stakeholders' opinions ................................................................................................................. 157
3.3. Distribution network tariffs and DSO remuneration .................................................................... 161
3.3.1. Summary table ............................................................................................................................. 162
3.3.2. Description of the baseline .......................................................................................................... 164
3.3.3. Deficiencies of the current legislation ......................................................................................... 168
3.3.4. Presentation of the options ......................................................................................................... 169
3.3.5. Comparison of the options .......................................................................................................... 170
3.3.6. Subsidiarity................................................................................................................................... 172
3.3.7. Stakeholders' opinions ................................................................................................................. 173
3.4. Improving the institutional framework ....................................................................................... 179
3.4.2. Summary Table ............................................................................................................................ 180
3.4.1. Description of the baseline .......................................................................................................... 181
3.4.2. Deficiencies of the current legislation ......................................................................................... 185
3.4.3. Presentation of the options ......................................................................................................... 189
3.4.4. Comparison of the options .......................................................................................................... 195
3.4.5. Budgetary implications of improved ACER staffing ..................................................................... 198
3.4.6. Subsidiarity................................................................................................................................... 200
3.4.7. Stakeholders' opinions ................................................................................................................. 202
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
1.1.1.
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 compensation and non-discrimination is
stream, particularly for high variable cost however result in significant loss of market efficiency if ensured, priority grid access may remain
generation.
large shares of consumption were to be covered by small necessary also after the abolishment of priority
installations.
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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1.1.2.
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,
5
Priority access and dispatch
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Directive 2004/8/EC, have been expanded in the Energy Efficiency Directive to include
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.
1.1.3.
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.
6
Priority access and dispatch
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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
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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where the market 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;
-
-
-
-
-
8
Consentec,
"Konventionelle Mindesterzeugung
Einordnung, aktueller Stand und perspektivische
Behandlung",
Abschlussbericht 25. Januar 2016, p. vii and 25.
8
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-
Priority dispatch rules for generation installations using indigenous ressources
result in clear discrimination of cross-border flows and distortions to the internal
market.
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).
1.1.4.
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.
9
KEMA study commissioned for the EU Commission (ENER/C1/427-2010, Final report of 12 June
2014), p.183 f.
9
Priority access and dispatch
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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
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
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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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.
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.
1.1.5.
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
11
Priority access and dispatch
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-
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;
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.
12
13
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)
For more details please see Section 6.1.2 of the impact assessment.
12
Priority access and dispatch
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1730781_0013.png
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
14
The environmental impacts from the removal of priority dispatch for biomass are discussed in Section
6.1.6 of the impact assessment
13
Priority access and dispatch
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combination of Options 2 and 3. This will allow a reduction of the administrative impact
for households and SMEs while ensuring the most efficient use of bigger mature power
generators.
1.1.6.
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.
1.1.7.
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
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.
14
Priority access and dispatch
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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.
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
17
http://www.eurobat.org/sites/default/files/eurobat_batteryenergystorage_web.pdf
p.28.
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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 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
Priority access and dispatch
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1.2. Regulatory exemptions from balancing responsibility
17
Regulatory exemptions from balancing responsibility
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1.2.1.
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.
Cons
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.
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.
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1.2.2.
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
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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Regulatory exemptions from balancing responsibility
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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 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.
1.2.3.
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
20
Regulatory exemptions from balancing responsibility
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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 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
22
KEMA study commissioned for the EU Commission (ENER/C1/427-2010, Final report of 12 June
2014), p.185
21
Regulatory exemptions from balancing responsibility
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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 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.
1.2.4.
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
23
24
25
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.
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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Regulatory exemptions from balancing responsibility
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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 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
23
Regulatory exemptions from balancing responsibility
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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
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.
1.2.5.
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
Regulatory exemptions from balancing responsibility
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1730781_0025.png
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.
1.2.6.
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
25
Regulatory exemptions from balancing responsibility
kom (2016) 0864 - Ingen titel
1730781_0026.png
both investment decisions and trading on electricity markets; every decision to sell
electricity 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.
1.2.7.
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
26
http://www.ewea.org/fileadmin/files/library/publications/position-papers/EWEA-position-paper-
balancing-responsibility-and-costs.pdf
26
Regulatory exemptions from balancing responsibility
kom (2016) 0864 - Ingen titel
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
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
Regulatory exemptions from balancing responsibility
kom (2016) 0864 - Ingen titel
28
Regulatory exemptions from balancing responsibility
kom (2016) 0864 - Ingen titel
1.3. RES E access to provision of non-frequency ancillary services
29
RES E access to provision of non-frequency ancillary services
kom (2016) 0864 - Ingen titel
1730781_0030.png
1.3.1.
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 technical capabilities of RES E and other new technologies is Allows gradual phase-in of services based on local/regional needs
and best practices.
non-frequency ancillary services.
available, main hurdle is regulatory framework.
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.
RES E access to provision of non-frequency ancillary services
kom (2016) 0864 - Ingen titel
1730781_0031.png
1.3.2.
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
RES E access to provision of non-frequency ancillary services
kom (2016) 0864 - Ingen titel
1730781_0032.png
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
RES E access to provision of non-frequency ancillary services
kom (2016) 0864 - Ingen titel
1730781_0033.png
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.
-
-
1.3.3.
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
33
RES E access to provision of non-frequency ancillary services
kom (2016) 0864 - Ingen titel
1730781_0034.png
services have a geographical 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."
1.3.4.
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
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
RES E access to provision of non-frequency ancillary services
kom (2016) 0864 - Ingen titel
1730781_0035.png
have a significant impact on the competitiveness of electricity generation, which
competes cross-border.
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.
1.3.5.
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
35
RES E access to provision of non-frequency ancillary services
kom (2016) 0864 - Ingen titel
1730781_0036.png
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 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.
1.3.6.
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
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
36
RES E access to provision of non-frequency ancillary services
kom (2016) 0864 - Ingen titel
1730781_0037.png
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 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.
1.3.7.
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
.
"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
32
37
RES E access to provision of non-frequency ancillary services
kom (2016) 0864 - Ingen titel
1730781_0038.png
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 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
38
RES E access to provision of non-frequency ancillary services
kom (2016) 0864 - Ingen titel
1730781_0039.png
2. D
ETAILED MEASURES ASSESSED UNDER
P
ROBLEM
A
REA
I,
S
TRENGTHENING SHORT
-
TERM MARKETS
OPTION
1(
B
)
39
RES E access to provision of non-frequency ancillary services
kom (2016) 0864 - Ingen titel
40
RES E access to provision of non-frequency ancillary services
kom (2016) 0864 - Ingen titel
2.1. Reserves sizing and procurement
41
Reserves sizing and procurement
kom (2016) 0864 - Ingen titel
1730781_0042.png
2.1.1.
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 of Option 2: regional sizing and procurement 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 binding regulation requiring TSOs to use regional
Balancing Guideline. Existing
platforms for the procurement of balancing
regulation that would require TSOs to size
on-going experiences will remain
their balancing reserves on daily probablistic reserves. Therefore this option foresees the
and be free to develop further, if
implementation of an optimisation process for
methodologies. Daily calculation allows
so decided. However, sizing and
the allocation of transmission capacity between
procuring lower balancing reserves and,
procurement of balancing
energy and balancing markets, which then
together with daily procurement, enables
reserves will mainly remain
implies procuring reserves only a day ahead of
participation of renewable energy sources
national as foreseen in the
and demand response.
real time
.
Balancing Guideline.
This option foressees separate procurement
This option would result in a higher level of
of all type of reserves between upward (i.e.
coordination between European TSOs, but still
Active participation in the
increasing power output) and downward (i.e. relies on the concept of local responsibilities of
Balancing Stakeholder Group
reducing power output; offering demand
individual balancing zones and remains
could ensure stronger
reduction) products.
compatible with current operational security
enforcement of the Balancing
principles.
Guideline.
Description
Pros
Pro
optimal national sizing and
procurement of balancing reserves
Con
no cross-border optimisation of
balancing reserves
Pro
–regional
areas for sizing and procurement
of balancing reserves
Con
balancing zones still based on national
borders but cross-border optimisation possible
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.
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
Reserves sizing and procurement
kom (2016) 0864 - Ingen titel
1730781_0043.png
2.1.2.
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.
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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-
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, 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
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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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 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
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reserves that need to be 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.
2.1.3.
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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2.1.4.
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
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exchange of balancing capacity requires firm cross-zonal transmission capacity.
Therefore 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.
2.1.5.
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
43
ENTSO-E supporting document for the Network Code on Load-Frequency Control and Reserves,
2013, pp. 75
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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 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.
2.1.6.
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.
2.1.7.
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.
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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
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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2.2.1.
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.
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.
Pros
Differences in national markets will remain that can act as a
barrier.
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.
Option 1
Fully harmonise all arrangements in local
markets.
Option 2
Selected harmonisation, specifically on issues relating to gate closure
times and products.
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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2.2.2.
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
IT
PT
DE
GB
SI
BE
SE
LT
FR
CZ
NL
PL
12.1% 7.4% 7.6% 4.6% 4.4% 1.0% 1.0% 1.0% 1.0% 0.7% 0.7% 0.2% 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.
2.2.3.
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.
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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
and network because of the minor attention in it to effective short-term markets and
prices which would reflect actual scarcity."
46
2.2.4.
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
46
Section 7.3.2 of the Evaluation
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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.
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.
2.2.5.
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.
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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, 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
2.2.6.
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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2.2.7.
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
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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balancing markets will be increasingly important to valuing flexibility and there needs to
be a push 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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2.3.1.
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.
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.
Most suitable: Most suitable option(s): Option 1
(Option 2 and Option 3 constitute the long-term vision)
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2.3.2.
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
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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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), 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
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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.
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.
2.3.3.
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.
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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 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.
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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 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.
2.3.4.
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.
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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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 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.
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.
iii.
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)
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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 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.
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.
iii.
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.
2.3.5.
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
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qualitative, 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
x
x
x
x
x
x
x
x
x
x
x
58
x
57
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
59
minimising the risk of blackouts
60
0/+
+
++
++
Lowering costs through increased
61
efficiency in system operation
62 63
0/+
++
+++
+++
Maximising transmission capacity
64
offered to the market
0/+
++
+++
+++
59
60
61
62
63
64
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.
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Reducing the need of remedial
actions by coordinating and
activating in a coordinated way
65 66
redispatching
Minimising the costs of balancing
provision by taking a more
coordinated approach towards the
67 68
sizing of balancing reserves
69
0/+
++
+++
+++
0/+
++
+++
+++
Optimisation
70
planning
of
infrastructure
0
0
++
+++
65
66
67
68
69
70
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
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.
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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 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 p