Europaudvalget 2016
KOM (2016) 0863
Offentligt
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EUROPEAN
COMMISSION
Brussels, 30.11.2016
SWD(2016) 410 final
PART 3/5
COMMISSION STAFF WORKING DOCUMENT
IMPACT ASSESSMENT
Accompanying the document
Proposal for a Directive of the European Parliament and of the Council on common
rules for the internal market in electricity (recast)
Proposal for a Regulation of the European Parliament and of the Council on the
electricity market (recast)
Proposal for a Regulation of the European Parliament and of the Council establishing
a European Union Agency for the Cooperation of Energy Regulators (recast)
Proposal for a Regulation of the European Parliament and of the Council on risk
preparedness in the electricity sector
{COM(2016) 861 final}
{SWD(2016) 411 final}
{SWD(2016) 412 final}
{SWD(2016) 413 final}
EN
EN
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TABLE OF CONTENTS
1. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA I, OPTION 1(A):
LEVEL PLAYING FIELD AMONGST PARTICIPANTS AND RESOURCES ......................4
1.1. Priority access and dispatch .............................................................................................................. 4
Summary table ................................................................................................................................. 4
Description of the baseline .............................................................................................................. 5
Deficiencies of the current legislation ............................................................................................. 6
Presentation of the options ............................................................................................................. 9
Comparison of the options ............................................................................................................ 11
Subsidiarity ..................................................................................................................................... 14
Stakeholders' opinions ................................................................................................................... 14
1.2. Regulatory exemptions from balancing responsibility ..................................................................... 17
Summary table ............................................................................................................................... 18
Description of the baseline ............................................................................................................ 19
Deficiencies of the current legislation ........................................................................................... 20
Presentation of the options ........................................................................................................... 22
Comparison of the options ............................................................................................................ 24
Subsidiarity ..................................................................................................................................... 25
Stakeholders' opinions ................................................................................................................... 26
1.3. RES E access to provision of non-frequency ancillary services ......................................................... 29
Summary table ............................................................................................................................... 30
Description of the baseline ............................................................................................................ 31
Deficiencies of the current legislation ........................................................................................... 33
Presentation of the options ........................................................................................................... 34
Comparison of the options ............................................................................................................ 35
Subsidiarity ..................................................................................................................................... 36
Stakeholders' opinions ................................................................................................................... 37
2. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA I, OPTION 1(B)
STRENGTHENING SHORT-TERM MARKETS .................................................................. 39
2.1. Reserves sizing and procurement .................................................................................................... 41
Summary table ............................................................................................................................... 42
Description of the baseline ............................................................................................................ 43
Deficiencies of the current legislation (see also Section 7.4.2 of the evaluation) ......................... 47
Presentation of the options ........................................................................................................... 48
Comparison of the options ............................................................................................................ 49
Subsidiarity ..................................................................................................................................... 50
Stakeholders' opinions ................................................................................................................... 50
2.2. Removing distortions for liquid short-term markets ....................................................................... 53
Summary table ............................................................................................................................... 54
Description of the baseline ............................................................................................................ 55
Deficiencies of the current legislation ........................................................................................... 58
Presentation of the options ........................................................................................................... 59
Comparison of the options ............................................................................................................ 60
Subsidiarity ..................................................................................................................................... 62
Stakeholders' opinions ................................................................................................................... 63
2.3. Improving the coordination of Transmission System Operation ...................................................... 65
Summary table ............................................................................................................................... 66
2
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Detailed description of the baseline .............................................................................................. 67
Deficiencies of the current legislation ........................................................................................... 70
Presentation of the options ........................................................................................................... 72
Comparison of the options ............................................................................................................ 76
Subsidiarity ..................................................................................................................................... 88
Stakeholders' opinions ................................................................................................................... 89
3. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA I, OPTION 1(C);
PULLING DEMAND RESPONSE AND DISTRIBUTED RESOURCES INTO THE
MARKET .................................................................................................................................... 90
3.1. Unlocking demand side response .................................................................................................... 92
Summary table ............................................................................................................................... 93
Description of the baseline ............................................................................................................ 94
3.1.2.1. Smart Metering ...................................................................................................................... 94
3.1.2.2. Market arrangements for demand response ......................................................................... 96
Deficiencies of current legislation ................................................................................................ 102
3.1.3.1. Deficiencies of current Smart Metering Legislation ............................................................. 102
3.1.3.2. Deficiencies of current regulation on demand response ..................................................... 103
Presentation of the options ......................................................................................................... 104
Comparison of the options .......................................................................................................... 107
Subsidiarity ................................................................................................................................... 126
Stakeholders' opinions ................................................................................................................. 130
3.2. Distribution networks ................................................................................................................... 143
Summary table ............................................................................................................................. 144
Description of the baseline .......................................................................................................... 145
Deficiencies of current legislation ................................................................................................ 150
Presentation of the options ......................................................................................................... 152
Comparison of the options .......................................................................................................... 152
Subsidiarity ................................................................................................................................... 156
Stakeholders' opinions ................................................................................................................. 157
3.3. Distribution network tariffs and DSO remuneration...................................................................... 160
Summary table ............................................................................................................................. 161
Description of the baseline .......................................................................................................... 163
Deficiencies of the current legislation ......................................................................................... 167
Presentation of the options ......................................................................................................... 168
Comparison of the options .......................................................................................................... 169
Subsidiarity ................................................................................................................................... 171
Stakeholders' opinions ................................................................................................................. 172
3.4. Improving the institutional framework ......................................................................................... 177
Summary Table ............................................................................................................................ 178
Description of the baseline .......................................................................................................... 179
Deficiencies of the current legislation ......................................................................................... 183
Presentation of the options ......................................................................................................... 187
Comparison of the options .......................................................................................................... 194
Budgetary implications of improved ACER staffing ..................................................................... 197
Subsidiarity ................................................................................................................................... 199
Stakeholders' opinions ................................................................................................................. 200
3
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1. D
ETAILED MEASURES ASSESSED UNDER
P
ROBLEM
A
REA
I,
OPTION
1(
A
):
LEVEL PLAYING FIELD AMONGST PARTICIPANTS AND RESOURCES
1.1. Priority access and dispatch
Summary table
Objective:
To ensure that all technologies can compete on an equal footing, eliminating provisions which create market distortions unless clear necessity is demonstrated, thus ensuring that
the most efficient option for meeting the policy objectives is found. Dispatch should be based on the most economically efficient solution which respects policy objectives.
Option 0
Option 1
Option 2
Option 3
Do nothing.
Abolish priority dispatch and priority Priority dispatch and/or priority access only for emerging Abolish priority dispatch and introduce clear
This would maintain access
technologies and/or for very small plants:
curtailment and re-dispatch rules to replace
rules allowing priority This option would generally require full This option would entail maintaining priority dispatch priority access.
dispatch and priority merit order dispatch for all technologies, and/or priority access only for small plants or emerging This option can be combined with Option 2,
access
for
RES, including RES E, indigenous fuels such as technologies. This could be limited to emerging RES E maintaining priority dispatch/access only for
indigenous fuels and coal, and CHP. It would ensure optimum technologies, or also include emerging conventional emerging technologies and/or for very small
plants
CHP.
use of the available network in case of technologies, such as CCS or very small CHP.
network congestion.
Lowest
political Efficient use of resources, clearly Certain emerging technologies require a minimum number As Option 1, but also resolves other causes for
resistance
distinguishes
market-based
use
of of running hours to gather experiences. Certain small lack of market transparency and discrimination
capacities and potentially subsidy-based generators are currently not active on the wholesale market. potential. It also addresses concerns that
installation of capacities, making subsidies In some cases, abolishing priority dispatch could thus bring abolishing priority dispatch and priority access
transparent.
significant challenges for implementation. Maintaining also could result in negative discrimination for
priority access for these generators further facilitates their renewable technologies.
operation.
Politically, it may be criticized that Same as Option 1, but with less concerns about blocking Legal clarity to ensure full compensation and
subsidized resources are not always used if potential for trying out technological developments and non-discriminatory curtailment may be
there are lower operating cost alternatives. creating administrative effort for small installations. challenging to
establish.
Unless
full
Adds uncertainty to the expected revenue Especially as regards small installations, this could however compensation and non-discrimination is
stream, particularly for high variable cost result in significant loss of market efficiency if large shares ensured, priority grid access may remain
generation.
of consumption were to be covered by small installations.
necessary also after the abolishment of priority
dispatch.
Most suitable option(s): Option 3.
Abolishing priority dispatch and access exposes generators to market signals from which they have so far been shielded, and requires all generators to
actively participate in the market. This requires clear and transparent rules for their market participation, in order to limit increases in capital costs and ensure a level playing field. This should
be combined with Option 2: while aggregation can reduce administrative efforts related thereto, it is currently not yet sufficently developed to ensure also very small generators and/or emerging
technologies could be active on a fully level playing field; they should thus be able to benefit from continuing exemptions.
Cons
Pros
Description
4
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Description of the baseline
Dispatch rules determine which power generation facilities shall generate power at which
time of the day. In principle, this is based on the so-called merit order, which means that
those power plants which for a given time period require the lowest payment to generate
electricity are called upon to generate electricity. This is determined by the day-ahead and
intraday markets. In most Member States, dispatch is then first decided by market results
and, where system stability requires intervention, corrected by the TSO (so-called self-
dispatch systems). In some Member States (e.g. Poland) the TSO integrates both steps,
directly determining on the basis of the system capabilities and market offers made which
offers can be accepted (so-called central dispatch).
Access rules determine which generator gets, in case of congestion on a particular grid
element, access to the electricity network. They thus do not relate to the initial network
connection, but to the allocation of capacity in situations where the network is unable to
fully accommodate the market result. Priority access can thus mean that in situations of
congestion, instead of applying the most efficient way of remedying a particular network
issue, the transmission system operator has to opt for less efficient, more complex and/or
more costly options, to maintain full generation from the priority power plant.
Currently, several Directives allow the possibility or even set the obligation for Member
States to include priority dispatch and priority grid access of certain technologies in their
national legislation:
-
Article 15(4) of the Electricity Directive provides that Member States may foresee
priority dispatch of generation facilities using fuel from indigenous primary energy
fuel sources to an extent not exceeding, in any calendar year, 15 % of the overall
primary energy necessary to produce the electricity consumed in the Member State
concerned;
Article 16(2)(a) of the Renewable Energies Directive obliges Member States to
provide for either priority access or guaranteed access to the grid-system of
electricity produced from renewable energy sources;
Article 16(2)(c) of the Renewable Energies Directive obliges Member States to
ensure that when dispatching electricity generating installations, transmission
system operators shall give priority to generating installations using renewable
energy sources in so far as the secure operation of the national electricity system
permits and based on transparent and non-discriminatory criteria;
Similarly to the provisions under the Renewable Energies Directive, Article 15 (5)
b) and c) of the Energy Efficiency Directive foresee priority grid access and priority
dispatch of electricity from high-efficiency cogeneration respectively.
-
-
-
The introduction of priority dispatch and priority access for renewable energies on the one
hand and for CHP on the other hand are closely related. According to the impact
assessment of the Energy Efficiency Directive, Article 15 (5) aims at ensuring a level
playing field in electricity markets and help distributed CHP. Thus, the obligation of
priority dispatch, and the right to priority access, already existing under its predecessor,
Directive 2004/8/EC, have been expanded in the Energy Efficiency Directive to include
5
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mandatory priority access for CHP
1
. The new provision fully mirrored the provision under
the then new Renewable Energies Directive.
Already for Directive 2004/8/EC, priority dispatch and (the right for a Member State to
foresee) priority access were based on the "need to ensure a level playing field" and the
challenges for CHP being similar to those for renewable energies. The provision of priority
dispatch and priority access for CHP has thus since its beginning been closely related to
the provision of these rights to renewable energies. This is also reflected in the text of
Article 15(5) itself, which provides that "when
providing priority access or dispatch for
high-efficiency cogeneration, Member States may set rankings as between, and within
different types of, renewable energy and high-efficiency cogeneration and shall in any case
ensure that priority access or dispatch for energy from variable renewable energy sources
is not hampered."
The current framework thus provides that the provision of priority dispatch and priority
access for CHP shall under no circumstance endanger the expansion of renewable energies.
Against this background, any change to the framework for renewable energies would
directly impact the justification underlying the introduction of priority dispatch and priority
access for CHP.
The degree to which Member States have made use of the right under Article 15 (4) of the
Electricity Directive differs significantly. Some Member States make no use of it whereas
other Member States provide for priority dispatch of power generation facilities using
national resources (most notably coal). The provisions in the Renewable Energy Directive
and Energy Efficiency Directive are mandatory and in principle applied in all Member
States, although the implementation can differ significantly due to differences in national
subsidy schemes.
Deficiencies of the current legislation
European legislation allows the option (as regards indigenous resources) or sets an
obligation (for RES E and CHP) to implement priority dispatch and (for RES E and CHP)
priority grid access. This creates a framework with very high predictability of the total
power generation per year, thus increasing investment security. In particular in view of the
increasing share of RES E, this has resulted in a situation where in some Member States
very high shares of power generation are coming from "prioritized" sources.
The EU has committed to a continued increase of the share of renewable generation for the
coming decades. Until 2030, at least 27 % of final energy consumption in the EU shall
come from RES E
–
this requires a share of at least 45 % in power generation
2
. According
to the PRIMES EuCo27 scenario, decarbonisation of EU's energy system would require a
share of RES in power generation of close to 50%, wind and solar energy alone projected
to cover 29 % of power generation.
1
2
https://ec.europa.eu/energy/sites/ener/files/documents/sec_2011_0779_impact_assessment.pdf,
p.58.
2030 Communication, COM(2014) 15 final, p.6.
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Today, investments in renewable generation make up the largest share of investments;
many RES E technologies can no longer be treated as marginal or emerging technologies.
The comparison of Germany and Denmark, two Member States with high shares both of
RES E and CHP, is helpful to assess the deficiencies of systems based on strong priority
dispatch and priority access principles. Taking the example of Denmark, an average of 62
% of power demand in the month of January 2014 has come from wind generation alone
3
and the share of annual demand covered by wind power has risen from 19 % in 2009 to 42
% in 2015
4
. Adding to this the share of 50.6 % of CHP in total Danish power generation
5
,
which makes Denmark one of the Member States with the highest share of CHP
6
, in many
periods almost all generation would be subject to "priority dispatch". Finally, it may be
necessary to add certain generation assets which are needed to operate for system security,
e.g. because only they can provide certain system services (e.g. voltage control, spinning
reserves), further limiting the scope for fully market based generation. However, in
Denmark, market incentives on generators are set in a way that drastically reduces the
impact of priority dispatch. Almost all decentralized CHP plants and a large number of
wind turbines would be exposed to and are not willing to run at negative prices. As CHP
are not shielded from market signals by national support systems, they have strong
incentives to stop electricity generation in times of oversupply. The integration of a high
share of RES E and CHP in parallel has been successful to a significant extent because
CHP are
not
built and operated on the basis of a "must run" model, where heat demand
steers electricity generation. To the contrary, CHP plants have back-up solutions (boilers,
heat storage), and use these where this is more efficient for the electricity system as
expressed by wholesale prices.
Taking the example of another "renewables front runner", Germany, "must run"
conventional power plants have been found to contribute significantly to negative prices
in hours of high renewable generation and low load, with at least 20 GW of conventional
generation still active even at significantly negative prices
7
. Financial incentives are so that
many conventional plants generate even at significantly negative prices, with many power
plants switching off electricity generation only at prices around minus 60 EUR/MWh. This
increases the occurrence of negative prices, worsening the financial outlook for both
renewable and conventional generators, and can increase system stress and costs of
interventions by the system operator. This is not due to technical reasons
–
also in
Germany, CHP plants generally have back-up heat capacities, which are already necessary
to address e.g. maintenance periods of the main plant, or could technically install these.
While it may be economically and environmentally efficient to run through short periods
of low prices (to avoid ramping up or down), this is no longer the case where the market
3
4
5
http://www.martinot.info/renewables2050/how-is-denmark-integrating-and-balancing-renewable-
energy-today.
http://www.energinet.dk/EN/El/Nyheder/Sider/Dansk-vindstroem-slaar-igen-rekord-42-procent.aspx.
https://ec.europa.eu/energy/sites/ener/files/documents/PocketBook_ENERGY_2015%20PDF%20final.
pdf, p. 183.
http://www.code2-project.eu/wp-content/uploads/Code-2-D5-1-Final-non-pilor-Roadmap-
Denmark_f2.pdf;
See:
http://www.netztransparenz.de/de/Studie-konventionelle-Mindesterzeugung.htm
6
7
7
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is willing to pay a lot for electricity being
not
generated. Excess electricity is in these
situations not very efficiently generated, but essentially a waste product. While there is a
wide range of reasons for conventional generation to produce at hours of negative prices
(e.g. very inflexible technologies such as nuclear or lignite which need a long time to
reactivate), approximately 50 % of the plants in such a situation in Germany had at least
the capability for parallel heat production, and approximately 8-10 % of conventional
plants still producing at such moments were found to be heat-controlled CHP generation
8
.
In view of the EU target for at least 27 % of renewable energies in final energy
consumption (which according to PRIMES EuCo27 projections would require 47 % of
gross final electricity consumption to come from renewable energy), the high share of
priority dispatch and priority access-technologies will increasingly occur in other Member
States. This can have very significant impact on the well-functioning of the electricity
market. In particular:
-
Subsidy schemes based on priority dispatch (such as Feed-in Tariffs) often are
based on high running hours and a mitigation of market signals to the subsidized
generator. This means that non-subsidized generation is increasingly pushed out of
the market even where this is not cost-efficient;
Situations in which more than 100 % of demand is covered by priority dispatch
become more prevalent. This lowers the investment security provided by priority
dispatch, and can lead to results contrary to policy interests such as unnecessary
curtailment of RES E;
The internal energy market depends on steering the use of generation by price
signals. In a situation where the clear majority of power generation does not react
to price signals, market integration fails and market signals cannot develop;
Incentives to invest into increased flexibility which would naturally result from
price signals on a functioning wholesale market do not reach a significant part of
the generation mix. Priority dispatch rules can eliminate incentives for flexible
generation (e.g. biomass, some CHP with back-up installations) to use the
flexibility potential and instead create incentives to run independent of market
demand;
Priority dispatch and priority grid access limit the choice for transmission system
operators to intervene in the system (e.g. in case of congestion on certain parts of
the electricity grid). This can result in less efficient interventions (e.g. re-
dispatching power plants in suboptimal locations). The increased complexity with
high shares of priority dispatch could also lower system stability, although
emergency measures may also affect generation benefiting from priority dispatch;
Priority dispatch rules for high marginal cost technologies can result in using costly
primary ressources to generate electricity at a time where other, cheaper,
technologies were available;
Priority dispatch rules for generation installations using indigenous ressources
result in clear discrimination of cross-border flows and distortions to the internal
market.
-
-
-
-
-
-
8
Consentec,
"Konventionelle Mindesterzeugung
–
Einordnung, aktueller Stand und perspektivische
Behandlung",
Abschlussbericht 25. Januar 2016, p. vii and 25.
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Against this background, the provision of priority dispatch and priority grid access needs
to be reassessed in view of the main policy objectives of sustainability, security of supply
and competitiveness (see also Section 7.4.2 of the evaluation).
Presentation of the options
For the operation of generation assets, it is recognized that the wholesale market with
merit-order based dispatch and access ensures an optimal use of generation resources.
Especially in balancing, it also ensures optimal use of congested network capacities. Rules
which deviate from these provisions reduce system efficiency and result in market
distortions, as it can sometimes be economically more efficient to curtail RES and the
guarantee of non-curtailment significantly increases price volatility
9
. Where financial
compensation on market-based principles is foreseen in case of re-dispatch, priority
dispatch also does not appear to be necessary to mitigate investor risk in low marginal cost
technologies. Thus, it is proposed to abolish or at least significantly limit the exceptions
foreseen under EU law from merit-order based dispatch and network access.
Option 0: do nothing
This option does not change the legislative framework. Priority dispatch and access
provisions remain unchanged in EU legislation and the above-described problems persist.
Option 0+: Non-regulatory approach
Stronger enforcement would not adress the policy objectives. In fact, as the objective is to
ensure market-based use of generation assets with limited exceptions, stricter enforcement
of existing obligations under EU law which make those exceptions mandatory would be
counter-productive.
Voluntary cooperation does not change the legislative framework and thus maintains the
currently existing obligations. The order of dispatch for power plants and access to the grid
has clear cross-border implications. Priority dispatch/access often results in lower
availability of cross-border capacities, and significant differences in these rules can thus
distort cross-border trade.
Option 1: Abolish priority dispatch and priority access
Under this option, priority dispatch / priority access provisions would be removed from
EU legislation, and replaced by a general principle that generation and demand response
shall be dispatched on the basis of using the most efficient resources available, as
determined on the basis of merit order and system capabilities.
This option would optimally achieve the defined objectives and thus be highly effective.
It would however result in additional administrative impact for very small RES E
installations which are currently not capable of controlling their feed-in into the grid
(notably rooftop solar) and micro-CHP installations. Furthermore, it could increase
complexity and prolong the development time for emerging technologies. As these
technologies would not yet be mature they would not be able to generate at competitive
9
KEMA study commissioned for the EU Commission (ENER/C1/427-2010, Final report of 12 June
2014), p.183 f.
9
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prices and could thus not reach a number of running hours needed to generate sufficient
experience.
Option 2: Limit priority dispatch and/or priority access to emerging technologies and/or
small plants
Under this option, priority shall be given only where it can be justified to enable a certain
technology or operating model which is seen as beneficiary under other policy objectives.
As regards emerging technologies
10
, this could in particular be linked to ensuring that the
technologies reach a minimum number of running hours as required to gather experience
with the non-mature technology. For particularly small generation installations
11
, this
could reduce the administrative and technical effort linked to dispatching the power plant
for its owner, which may appear disproportionate for certain installations. This being said,
the administrative effort can be significantly reduced by ensuring the possibility of
aggregation, allowing the joint operation and management of a large number of small
plants. To mitigate negative impacts on market functioning, both possible exemptions
should be capped to ensure that priority dispatch and priority access does not apply to large
parts of total power generation.
This option would achieve the defined objectives, although certain trade-offs would be
made. Accepting priority dispatch and access for certain installations would reduce market
efficiency. If the share of exempted installations in the total electricity market remains low,
the negative market impact is however likely to remain very limited. On the other hand,
the positive impact of allowing the development of new technologies can provide a
significant benefit for the achievement of renewable energy targets in the medium to long-
term. Exempting very small installations would also increase public acceptance and reduce
administrative efforts required from the operators of these installations, which are often
households. This is thus the preferred option, although it has to be ensured that exemptions
remain limited to a small part of the market. The exact definition of the emerging
technologies could be left to subsidiarity.
Option 3: Abolish priority dispatch and introduce clear curtailment and re-dispatch rules
to replace priority access
This option (which can be combined with Option 2) would entail the abolishment of
priority dispatch. Priority grid access would be replaced by clear rules on how to deal with
situations of system stress, in particular as regards congestion of grid elements. In
principle, market-based ressources should be used first, thus curtailing or redispatching
first those generators which offer to do this against market-based compensation. In a
second step, where no market-based ressources can be used, minimum rules on
compensation are foreseen, ensuring compensation based on additional costs or (where this
is higher) a high percentage of lost revenues.
10
11
In the PRIMES EuCo27 scenario, the emerging technologies of tidal and solar thermal generation (other
technologies having insignificant shares) are projected to have a total installed capacity of 7.26 GW and
produce 10 TWh of electricity in 2030 (13 GW and 20 TWh in 2050, respectively).
In the PRIMES EuCo27 scenario, RES E small-scale capacity is projected in 2030 to be 85 GW (7.8 %
share) and produce 96 TWh of energy (2.9% share).
10
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It would mean that network operators would obtain a clear incentive to make an assessment
on the basis of costs as to the alternatives available to them to address the underlying
network constraints, thereby creating opportunities for more innovative solutions such as
storage.
The increase in transparency and legal certainty would notably also prevent discrimination
against certain technologies (particularly RES E) in curtailment and re-dispatch decisions.
RES E are often operated by smaller market players, who could otherwise be subject to
excessive curtailment or unable to achieve fully equal compensation. It would also foresee
principles on the financial compensation to be paid in case of curtailment or re-dispatch,
thus reducing the additional investment risk linked to losing priority access and thereby
reducing any increase in capital costs. In order to ensure effective implementation of the
new market rules prior to abolishment of priority dispatch and access, priority dispatch and
access may be maintained for an interim period after entry into force of the other measures
adressing Problem 1.
Increased transparency and legal certainty on curtailment and re-dispatch are a "no regret"
measure, in so far as they contribute to market functioning even in the absence of changes
to the priority dispatch and priority access framework. Ensuring sufficient compensation
for curtailment, notably for RES E, will increase costs to be borne by system operators. In
so far as these costs are currently integrated into renewable subsidy schemes, total system
costs will however remain similar. As regards priority grid access, this is the preferred
option, in order to ensure that the abolishment of priority grid access has no unwanted
negative consequences on the financial framework notably of RES E but also of CHP.
Comparison of the options
It should be noted that the removal of priority dispatch and priority access does not equally
affect different technologies and generators in different Member States:
-
The removal of priority dispatch mostly affects high marginal cost technologies
(biomass, indigenous resources, some CHP), as low marginal cost technologies
(wind, PV) are generally dispatched when available already on the basis of the
merit order. Without priority dispatch, high marginal cost technologies thus take
up a role more generally associated with other high marginal cost plants, such as
gas-fired power plants, operating only in periods of high prices (high residual load).
Those generators are then incentivized to making best use of the inherent flexibility
that their technology can provide to a power system, and thus accompany the
change to an electricity system with a high share of variable low marginal cost
generation. For high marginal cost generation, removal of priority dispatch can
significantly reduce the number of running hours. Studies for the Commission have
shown a reduction of approximately 85 % in dispatch of wood-based biomass
generation, mostly to the benefit of gas-fired power plants
12
. To the contrary, there
is a (more limited) increase in the running hours of low marginal cost generation,
including wind and solar;
12
For this assessment, biomass was assumed to consist of 22 % "must-run" waste incineration (OPEX: 3.6
EUR EUR/MWh) and 78 % wood-fired plants with high variable costs (around 90 EUR EUR/MWh)
11
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-
The reduction in inefficient biomass dispatch would represent a major part of the
significant reductions of system costs presented in Figure 1 below, with annual
savings of 5.9 billion Euros, expected by the removal of market distortions under
Problem Area I, Option (1a) of the impact assessment
13
;
Figure 1: Reduction in system costs by abolishment of priority rules
Source: METIS
-
By achieving market-based dispatch, the removal of priority dispatch for all
technologies drastically reduces the occurrence of negative prices. Whereas
negative prices can be a normal occurrence in well-functioning markets which have
opportunity costs linked to not offering a service (as is the case on the electricity
markets), the occurrence of negative prices based on priority rules shows that
priority is given also in times where the system does not require additional
generation.
13
For more details please see Section 6.1.2 of the impact assessment.
12
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Figure 2: reduction of negative price occurrences by removal of priority
dispatch
Source: METIS
-
-
-
The removal of priority access on the other hand mostly affects technologies which
are producing in areas and at times of network congestion. This will more often
concern low marginal cost technologies (especially wind) as periods of high wind
feed in are more likely to result in congested network elements, requiring
curtailment or re-dispatch;
Providing clear and transparent rules on curtailment and compensation benefits all
market actors. This is particularly true for small and/or new market actors,
including RES E;
While the change of biomass dispatch to reflect its role as flexible back-up
generation, to the benefit mostly of gas, but also of coal and nuclear generation
thus would drastically reduce future system costs, it could possible entail an
increase of CO2 emissions in the power sector, whereas total CO2 emissions under
the ETS framework would in principle remain identical over time
14
.
Option 1 would be the most effective in achieving the objective of non-discrimination and
market efficiency. However, it could result in an increase of costs to achieve other policy
objectives, notably for decarbonisation of the energy system. Fully removing priority
dispatch and access would also result in an increased need for small generators, including
households (e.g. rooftop solar) to participate in the electricity market. While this would
allow strong economic incentives, it would thus increase the administrative impact for
households and SMEs. Thus, clear and transparent rules for the market participation of
RES E and CHP as well as limited exemptions for small and emerging technologies should
be included, to accompany the phase-out of priority access and priority dispatch. On the
other hand, remaining at the
status quo
would, with a growing share of priority
technologies in the system, seriously undermine effective price formation and dispatch in
the wholesale market. The preferred option is thus a combination of Options 2 and 3. This
14
The environmental impacts from the removal of priority dispatch for biomass are discussed in Section
6.1.6 of the impact assessment
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will allow a reduction of the administrative impact for households and SMEs while
ensuring the most efficient use of bigger mature power generators.
Subsidiarity
Priority dispatch is foreseen directly in EU law. Changing or removing those provisions
cannot be achieved on a national level. Furthermore, in an integrated electricity market,
the way to determine which power plant is operated has a direct impact on cross-border
trade. Applying discriminatory provisions for power plant dispatch in certain Member
States can thus negatively affect cross-border trade or even directly result in discrimination
against power generators in other Member States. Ensuring efficient market integration
and functioning investment signals, requires fundamental dispatch rules to be harmonized.
Stakeholders' opinions
In the public consultation, most stakeholders support the full integration of Renewable
energy sources into the market, e.g. through full balancing obligations for renewables,
phasing-out priority dispatch and removing subsidies during negative price periods. Many
stakeholders note that the regulatory framework should enable RES E to participate in the
market, e.g. by adapting gate closure times and aligning product specifications. A number
of respondents also underline the need to support the development of aggregators by
removing obstacles for their activity to allow full market participation of renewables.
Also stakeholders from the renewable sector often recognize the need to review the priority
dispatch framework. They make this however subject to conditions; Wind Europe provided
views on curtailment of wind power and priority dispatch and stated that "countries
with
well integrated day-ahead, intraday and balancing market and a good level of
interconnections, where priority of dispatch is not granted to CHP and conventional
generators, do not need to apply priority of dispatch for wind power."
They argue that "in
general, priority dispatch should be set according to market maturity and liberalisation
levels in the Member State concerned, but also taking due account of progress in grid
developments and application of best practices in system operation."
According to its
paper from June 2016 on curtailment and priority dispatch, in the view of Wind Europe
15
,
some EU markets, such as Sweden and the UK, which have relatively high penetration
rates of wind, do not offer priority dispatch for wind producers
16
and this does not place
any restrictions on market growth. However, a phase-out of priority dispatch for renewable
energies should only be considered if (i) this is done also for all other forms of power
generation, (ii) liquid intraday markets with gate closure near real-time, (iii) balancing
markets allow for a competitive participation of wind producers; (short gate closure time,
separate up/downwards products, etc.), and (iv) curtailment rules and congestion
management are transparent to all market parties. According to Wind Europe, these
requirements are already in 2016 fulfilled in certain markets such as the UK, Sweden and
Denmark, whereas other Markets currently still required priority dispatch. It is the view of
the Commission services that by entry into force of the present legislative initiative, the
above requirements are met in all Member States.
15
16
https://windeurope.org/wp-content/uploads/files/policy/position-papers/WindEurope-Priority-
Dispatch-and-Curtailment.pdf.
The Commission services interpret this to mean that, while priority dispatch may be foreseen under
national legislation, it has no practical impact.
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Regarding priority access, Wind Europe asks for curtailments to be valued by the market
as a service to ensure system security. It should be treated as downward capacity and its
price should be set via the balancing market. This would already be applied in the Danish
and UK markets. Participation of wind in the balancing markets could lead to a significant
reduction of curtailments. This is taken into account in Option 3, which ensures the primary
use of available market-based ressources prior to any non-market based curtailment.
Where balancing ressources are available, including from RES E, and capable of adressing
the system problem underlying the planned curtailment, they thus have to be used before
non-market based curtailment takes place. For this second step, transparent compensation
rules are foreseen. Wind Europe recognizes that
"there may be a benefit from not
compensating 100% of the opportunity cost. Reducing slightly the income could send an
important incentive signal to investors to select locations with existing sufficient network
capacity, Curtailment would then be likely to occur less frequently. The exact % of the
opportunity cost needs to be carefully assessed in order to find a balance between an
increase in policy cost and the increase of financing costs due to higher market risk."
This
position is reflected in the present proposal.
Stakeholders from the cogeneration sector underline the link to priority dispatch for
renewable energies. COGEN Europe submits that it is "important
that at EU level CHP
benefits from at least parity with RES on electricity provisions, as long as there are no
additional policy measures that would compensate for the loss in optimal operation
ensured through priority of dispatch for certain types of CHPs."
They also argue that
"while
a significant fraction of the CHP fleet can be designed and/or retrofitted to operate
in a more flexible way (e.g. though partial load capabilities, enhanced design from the
electrical components, and the heat storage addition), this may come at the expense of the
site efficiency and industrial productivity."
The parallelism to RES is maintained in all
options, whereas the additional costs and possible loss of efficiency have to be balanced
with the economic cost of significant amounts of inflexible conventional generation in a
high-RES system.
EUROBAT, association of European Manufacturers of automotive, industrial and energy
storage batteries, regards curtailing of energy as a system failure, as the "wasted" power
should be stored in batteries instead. It argues against any financial compensation to
renewable generators for being curtailed, as such a compensation would disincentivize the
installation of energy storage systems
17
.
Transmission system operators would be directly affected, as they are responsible for
practical implementation of the priority rules. In May 2016, ENTSO-E has asked their
Members to provide answers to questions which had been discussed with the Commission
services. 29 TSOs from 25 countries have replied, though not all TSOs answered all
questions, which is also due to the limited impact of priority dispatch/access in some
Member States (with a low share of CHP and RES E). TSOs from 14 Member States
answered that priority dispatch increases the costs of pursuing stable, secure and reliable
system operations. TSOs from a smaller group of Member States (4 to 6) also stated that
priority dispatch limits the possibilities to keep the grid stable, secure and reliable. Only
the TSOs of three Member States answered that priority dispatch has no major effect on
system operations. Regarding the market impact, TSOs from 12 Member States raised
17
http://www.eurobat.org/sites/default/files/eurobat_batteryenergystorage_web.pdf
p.28.
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increased dispatching costs and 9 raised the occurrence of negative prices. On the other
hand, TSOs from one Member State argued that priority dispatch resulted in reduced costs
for the support of RES E. TSOs also stressed the cross-border impact of priority dispatch:
TSOs from 6 Member States referred to increased congestion of interconnectors, and an
example provided was that priority dispatch in neighbouring areas impacted the system
operation in the TSOs area. When asked how European legislation should adress the issues
mentioned, no TSO wanted to retain priority dispatch, 8 TSOs wanted to retain it with
exemptions, 4 TSOs wanted a phase out of priority dispatch, and 13 TSOs wanted priority
dispatch to be removed entirely.
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1.2. Regulatory exemptions from balancing responsibility
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Summary table
Objective:
To ensure that all technologies can compete on an equal footing, eliminating provisions which create market distortions unless clear necessity is demonstrated, thus ensuring that
the most efficient option for meeting the policy objectives is found. Each entity selling electricity on the market should be responsible for imbalances caused.
Option 0
Option 1
Option 2
Option 3
Do nothing.
This would maintain the
status
quo,
expressly requiring financial
balancing responsibility only under
the State aid guidelines which
allow for some exceptions.
Lowest political resistance
Full balancing responsibility for all parties
Each entity selling electricity on the
market has to be a balancing responsible
party and pay for imbalances caused.
Balancing responsibility with exemption
possibilities for emerging technologies
and/or small installations
This would build on the EEAG.
Balancing responsibility, but possibility to delegate
This would allow market parties to delegate the
balancing responsibility to third parties.
This option can be combined with the other options.
Description
Shielding from balancing responsibilities
creates serious concerns that wrong
incentives reduce system stability and
endanger market functioning. It can increase
reserve needs, the costs of which are partly
socialized. This is particularly relevant if
those exemptions cover a significant part of
the market (e.g. a high number of small RES
E generators).
Most suitable option(s): Option 2
combined with the possibility for delegation based on freely negotiated agreements.
Costs get allocated to those causing them.
By creating incentives to be balanced,
system stability is increased and the need
for reserves and TSO interventions gets
reduced. Incentives to improve e.g.
weather forecasts are created.
Financial risks resulting from the
operation of variable power generation
(notably wind and solar power) are
increased.
Cons
Pros
This could allow shielding emerging
technologies or small installations from the
technical and administrative effort and
financial risk related to balancing
responsibility.
The impact of this option would depend on the
scope and conditions of this delegation. A
delegation on the basis of private agreements, with
full financial compensation to the party accepting
the balancing responsibility (e.g. an aggregator)
generally keeps incentives intact.
The impact of this option would depend on the
scope and conditions of this delegation. A full and
non-compensated delegation of risks e.g. to a
regulated entity or the incumbent effectively
eliminates the necessary incentives. Delegation to
the incumbent also results in further increases to
market dominance.
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Description of the baseline
Balancing responsibility refers to the obligation of market actors (notably power
generators, demand response providers, suppliers, traders and aggregators) to
deliver/consumer exactly as much power as the sum of what they have sold and/or
purchased on the electricity market. Predictions for demand and (to a more limited extent)
generation being not 100 % precise, market actors are often not fully balanced. The
Transmission System Operator then ensures that total demand and supply are maintained
in balance by activating (upward or downward) balancing energy, often coming from
dedicated balancing capacities.
Balancing responsibility implies that the costs of the balancing actions taken by the
transmission system operator are generally to be compensated by the market parties which
are in imbalance. In some Member States, certain types of power generation (notably wind
and solar, but possibly also other technologies such as biomass) are excluded from this
obligation or have a differentiated treatment. Most Member States foresee some degree of
balancing responsibility also for renewable generators; based on an EWEA (now Wind
Europe) study, in 14 out of 18 Member States with a wind power share above 2-3 % in
annual generation, wind generators had some form of balancing responsibility
18
. This
however does not always translate into real financial responsibility of the generator for
imbalances it caused. In Austria for example, a public entity, OEMAG, acts as balancing
responsible party for all subzidized renewable generation, thus shielding individual
generators from imbalance risks of their power plants
19
and collectively purchasing/selling
balancing energy for the renewable sector
20
. On the other hand, in a small number of
Member States balancing costs imposed on renewable power generation can be
prohibitively high and almost reach the level of wholesale prices (e.g. incurred balancing
costs of up to 24 EUR/MWh in Bulgaria and 8-10 EUR/MWh in Romania)
21
.
Article 28 (2) of the Balancing Guideline provides that
"each balance responsible party
shall be financially responsible for the imbalance to be settled with the connecting TSO".
This does not, however, preclude frameworks in which market actors are (fully or partly)
shielded from the financial consequences of imbalances caused by having this
responsibility shifted to another entity. This is part of some current support schemes.
The EEAG provide that in order for State aid to be justified, RES E generators need to bear
full balancing responsibility unless no liquid intra-day market exists. The EEAG rules
however do not apply where no liquid intraday market exists, and and also do not apply to
installations with an installed electricity capacity of less than 500 kW or demonstration
projects, except for electricity from wind energy where an installed electricity capacity of
3 MW or 3 generation units applies. The exemption from balancing responsibility in the
absence of liquid intra-day markets is based on the reasoning that were liquid intra-day
18
19
20
21
http://www.ewea.org/fileadmin/files/library/publications/position-papers/EWEA-position-paper-
balancing-responsibility-and-costs.pdf,
p. 5-6.
https://www.energy-
community.org/portal/page/portal/ENC_HOME/DOCS/2014187/0633975ACF8E7B9CE053C92FA8
C06338.PDF
http://www.oem-ag.at/de/oekostromneu/ausgleichsenergie/.
http://www.ewea.org/fileadmin/files/library/publications/position-papers/EWEA-position-paper-
balancing-responsibility-and-costs.pdf
p. 8.
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markets
do
exist, they allow renewable generators to drastically reduce their imbalances
by trading electricity on short-term markets and thus taking account of updated wheather
forecasts. This shows that imposition of balancing responsibility is thus closely linked to
the creation of liquid short-term markets, one of the main objectives of the electricity
market design initiative.
The corollary to balancing responsibility is the possibility to participate in the balancing
market, offering balancing capacity to the TSO against remuneration. This is further
described under Section 5.1.1.4 and closely linked to the Balancing Guideline.
Deficiencies of the current legislation
Already today, the increased share of renewable energies in power generation
(approximately 29% in 2015) has significant impact on market functioning and grid
operation. This effect is most noticeable in Member States with RES E shares above the
EU average.
The below figure shows two relevant weeks, with production and consumption shown
together. In the left graph, generation exceeds the load (red line) in situation with lots of
solar power generation (yellow). In the right graph, less renewable power is generated
(blue, green, yellow, but minimal PV (yellow)). Supply and demand of electricity has to
match at all times despite changes in demand and variable renewable electricity
production. For both situations, flexibility options such as storage, demand side response,
flexible generation and interconnection import/export capacities are needed to take up
electricity.
Figure 1: Volatility in the German power market in June and December 2013
Source: Agora Energiewende 2013.
To integrate renewable production progressively and efficiently into a market that
promotes competitive renewables and drives innovation, energy markets and grids have to
be fit for renewables. This is not necessarily the case in many jurisdictions since markets
have traditionally been designed to cater the needs of conventional generation rather than
variable renewables. To make markets fit for renewables means developing adequately the
short-term markets such as intraday and balancing. This also means allowing, to the
maximum possible extent, renewables to participate in all electricity markets on equal
footing to conventional generation removing all existing barriers for renewable energy
20
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sources integration. Integrating RES E into the market and allowing them to generate a
large part of their revenues from market prices requires an increase of flexibility in the
system, which is also needed for absorbing cheap renewable electricity at times of high
supply. It is for this reason that the EEAG (para.124) requires generators to be subject to
standard balancing responsibilities only unless no liquid intra-day market exists. Liquid
intra-day markets should exist in all Member States at the expected date of entry into force
of the revised legislation, accompanying the present impact assessment. However, the
term "liquid intra-day market" allows significant margin of interpretation and can thus
cause uncertainty on the application of one of the fundamental rules on the electricity
market. It will be necessary to further clarify this exemption and ensure that market actors
have legal certainty as to whether they have to bear balancing responsibility or not.
Investment incentives should take into account the value of generation at different times
of the day or of the year. Progress has been made in this area, with support schemes relying
increasingly (but not everywhere or for all generation) on premiums instead of fixed feed-
in tariffs. Where premium-based support schemes are used, the degree of market exposure
depends on their exact implementation, differing e.g. between fixed and floating premium
models, and for the latter relative to the determination of the base price used for the
calculation of the premium. Full exposure to market signals may e.g. make a different
generation installation more efficient although it produces lower total output (such as
orienting PV to the west to increase output later in the day). By exposing generators to the
financial consequences of imbalances caused, the incentives given to generators do not
relate only to optimizing the expected generation of their power plant in view of market
needs, but also to ensuring that the electricity they sell on the market matches as closely as
possible the power produced at a certain point in time. In a questionnaire to TSOs
organized by ENTSO-E, the example was given that following the attribution of balancing
responsibility in a Member State, the average hourly imbalance of PV installations
improved from 11.2 % in 2010 to 7.0 % in March 2016, and the average hourly imbalance
of wind improved from 11.1 % to 7.4 % over the same period.
Where RES E generators do not assume balance responsibility identical to other generators
and participate in the balancing market, they lack incentives for efficient operational and
investment decisions
22
. Part of this challenge is the need to avoid inacceptable risks for
RES E investors by imposing balance responsibilities without creating the market
flexibility which allows staying balanced
23
. Whereas many Member States already foresee
some balancing responsibility for RES E generators (2013: 16 Member States)
24
this is not
22
23
24
KEMA study commissioned for the EU Commission (ENER/C1/427-2010, Final report of 12 June
2014), p.185
KEMA p. 185:
"Experience from some EU countries has shown that RES generators are able to provide
less volatile and more predictable generation schedules if so incentivized by balancing arrangements."
http://ec.europa.eu/energy/sites/ener/files/documents/com_2013_public_intervention_swd04_en.pdf
Appendix I table 6.
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yet the case for all Member States, and the degree of balancing responsibility differs
considerably between Member States. This can result in market distortions, directing
investments to Member States with lower degree of responsibility rather than to those
Member States where electricity demand and renewable generation potential are optimal,
and can also result in lower liquidity of short-term markets.
Reduced balancing responsibility can also result in increasing imbalances in electricity
trades. Whereas the TSO will generally, via the balancing market, be capable of covering
imbalances, a high degree of imbalances reduces predictability of system operation and
can increase system stress (e.g. by reducing the volume of available reserves) or increase
costs for system stability (e.g. if higher reserve volumes are procured in advance).
Finally, it should be noted that the EEAG already foresees the need to phase out
exemptions from balancing responsibilities in the post-2020 period
25
. The EEAG itself
provides in its paragraph 108 that the Guidelines
"apply to the period up to 2020 but should
prepare the ground for achieving the objectives set in the 2030 framework, implying that
subsidies and exemptions from balancing responsibilities should be phased out in a
degressive way".
Refrence is also made to Section 7.4.2 of the evaluation.
Presentation of the options
Balancing responsibility of all market parties active on the electricity market is a
fundamental principle of EU energy law. This principle should not be included only in a
State aid guideline and in the Balancing Guideline but ensured at the level of secondary
law, thus increasing transparency and legal certainty. Exemptions currently foreseen in the
guidelines need to be reassessed and, where still necessary, further clarified. It should also
be further clarified in how far and under which conditions delegation of this responsibility
is possible. It is thus proposed to establish a general rule that all market-related entities or
their chosen representatives shall be financially responsible for their imbalances, and that
any such delegation/representation shall not entail a disruption of incentives for market
parties to remain balanced. Provisions in this direction are already included in the
Balancing Guideline which will be discussed in Comitology in the second half of 2016.
General principles and, where applicable, exemptions shall be integrated into the
Electricity Directive for added clarity and legal certainty.
Option 0: do nothing
This would mean that balancing responsibility remains subject only to State aid rules and
the rules in the Balancing Guideline. Fundamental principles of electricity market
operation should systematically not be decided upon only in acts adopted under the
Comitology process and guidelines which undergo no legislative process. Furthermore, the
25
Paragraph 108 EEAG reads: "These
Guidelines apply to the period up to 2020. However, they should
prepare the ground for achieving the objectives set in the 2030 Framework. Notably, it is expected that
in the period between 2020 and 2030 established renewable energy sources will become grid-
competitive, implying that subsidies and exemptions from balancing responsibilities should be phased
out in a degressive way. These Guidelines are consistent with that objective and will ensure the transition
to a cost-effective delivery through market-based mechanisms."
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EEAG are limited in time to 2020 and uncertainty as to the extent of their exemptions and
their applicability post-2020 will persist. According to their paragraph 108, it is expected
that in the period between 2020 and 2030 established renewable energy sources will
become grid-competitive, implying that subsidies and exemptions from balancing
responsibilities should be phased out in a progressive way (and thus assuming liquid short-
term markets to develop). Finally The State aid guidelines only apply to those parts of
measures which are to be seen as State aid. This concerns most, but not necessarily all,
generation which may not be fully balancing responsible. For some aspects the
qualification as State aid could potentially be put into question.
Option 0+: Non-regulatory approach
As national law is extremely varied to date, without a clear and transparent framework
setting out the degree of balancing responsibility, enforcement of existing rules (e.g. State
aid rules) is unlikely to result in a uniform and non-discriminatory legal framework.
Voluntary cooperation can contribute to reducing the negative impact of imbalances.
Imbalance netting by transmission system operators already achieves significant cost
reductions. However, voluntary cooperation does not provide sufficient legal certainty and
the minimum degree of harmonization to avoid distortions in cross-border trade. In fact,
shielding certain market parties fully or in part from balancing responsibilities creates
economic advantages which can distort cross-border trade in electricity. Where a lack of
balancing responsibility results in increased imbalances, this will negatively impact the
whole synchronous area, and thus create costs and risks for system stability also in other
Member States.
Option 1: Full Balancing responsibility for all parties
This would entail that the principles of the Balancing Guideline imposing all market-
related entities and their representatives to be financially responsible for imbalances caused
would be integrated into the Electricity Directive.
This option would thus significantly increase transparency and legal certainty. Balancing
responsibility is already an accepted concept under the EEAG, so that the market impact
would be limited to those entities currently benefitting from exemptions or not subject to
State aid rules. While this option would optimally achieve the defined objective, the
complete abolishment of the existing exemptions could result in increased administrative
effort for small installations or demonstration projects using emerging technologies.
Option 2: Balancing responsibility with exemption possibilities for emerging technologies
and/or small installations
This would allow Member States to foresee that certain emerging technologies and/or
small installations (e.g. rooftop solar) are shielded from the direct financial impact of
imbalances they cause. As imbalances need to be covered by some entity, this could be
achieved by allocating it to public bodies (essentially meaning that these entities are acting
as sellers of RES E on the wholesale market), the costs of which are then socialized.
This option addresses the currently existing exemptions under EEAG, based on the
assumption that short-term markets have developed sufficiently by the time of entry into
force of the proposed legislation to require balancing responsibility of generators not
covered by the exemptions. Without introducing additional limitations, these exemptions
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would however risk reducing effectiveness in achieving the policy objective. This is
notably the case for small installations, which under some scenarios can account for a
significant part of total electricity supply.
Option 3: Possibility to delegate balancing responsibility
This option would entail the right to delegate balancing responsibilities to a third party.
Whereas the freely negotiated delegation to a third party against financial compensation
(e.g. an aggregator) can reduce administrative impact without reducing the incentive to
reduce imbalances (as their cost will be passed on to the generator in some way), regulated
delegations without compensation drastically reduce or eliminate the incentive to remain
balanced.
The possibility to delegate on the basis of free negotiation, against financial compensation,
(combined with exemptions notably for demonstration projects and possibly very small
installations) is the preferred option. It fully achieves the policy objectives, and allows
notably smaller installations to reduce administrative efforts without reducing market
incentives.
Comparison of the options
The requirement of full balancing responsibility does not affect all renewable technologies
in the same manner. Biomass and other non-variable technologies are generally capable of
being balanced to the same degree as conventional generators. Variable generators
(especially wind and PV) can increasingly predict their generation based on wheather
forecasts, but have a higher margin of error in those predictions than conventional
generators. To reduce the margin of error, those technologies need to improve wheather
forecasts, as well as sell electricity for shorter time periods in advance, when better
forecasts become available.
A study using METIS has shown very significant reductions in frequency restoration
reserve needs due to the introduction of balancing responsibilities for RES E. Whereas
FCR and aFRR needs relate to short-term frequency deviations and are thus not
significantly affected by balancing responsibility, mFRR needs are based on longer-lasting
deviations from indicated schedules. By creating incentives for improved forecasts and
more exact schedules, reserve needs are thus significantly reduced.
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Figure 2: reduction in reserve needs depending on balancing responsibility
Source: METIS
Option 1 would be most effective at achieving the objective of well-functioning markets.
All exemptions from balancing responsibility, even if only partly shielding against the
financial impact of imbalances, reduce the incentive to be balanced. The complete
abolishment of the existing exemptions would however result in increased administrative
effort for small installations or demonstration projects using emerging technologies. This
could slow down roll-out of new RES E technologies and could thus render the
achievement of the decarbonisation objective more costly. Options 2 and 3 can be
combined to ensure a maximum degree of balancing responsibility with the potential to
delegate this responsibility, which allows reduction of the additional administrative impact
imposed especially on small installations. This being said, small installations are currently
often not active on the market, and it could be excessive to require balancing responsibility
even taking into account the possibility to delegate. The preferred option is thus a
derogation from balancing responsibilities for demonstration projects and small generation
(e.g. rooftop solar), and the right for other projects to delegate their balancing responsibility
against financial compensation. This significantly reduces the administrative effort for
households and small and medium enterprises (who will often continue to benefit from
exemptions from balancing responsibilities) but takes account of the increased role
renewable generation plays in the market, and the improved capabilities particularly of
larger generators to predict their output and reduce or hedge remaining imbalance risks.
Subsidiarity
Balancing responsibility is a fundamental principle in every electricity market. It ensures
that market agreements are also reflected in the physical reality, and that the costs of
imbalances created are born by those creating them. Balancing responsibiltity impacts both
investment decisions and trading on electricity markets; every decision to sell electricity
25
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on the market entails the risk to be in imbalance, which thus has to be integrated into
bidding strategies. Deviations on a national level in an integrated market could result in
distortions of cross-border trade, e.g. by making investments into variable generation in
one Member State significantly more interesting than in other Member States, and basic
principles for balancing responsibility thus need to be harmonized.
Furthermore, increasing the share of RES E in the total energy consumption is an EU
target. For 2030, a target binding at EU level exists, without nationally binding targets;
therefore the EU has to ensure the EU target is reached. With an increasing share of RES
E, they become a relevant player on the power markets. As power markets are increasingly
integrated, this has direct cross-border impact. Equal treatment to all generation
technologies should be ensured to avoid market distortions. Markets should be fit to allow
all generation technologies and demand to compete on equal footing, while allowing the
EU to reach the policy objectives of sustainability, competitiveness and security of supply.
The increasing share of RES E also creates challenges for network operation. In
synchronous areas even exceeding the EU, this is an issue which cannot be resolved at
national level alone.
Stakeholders' opinions
In the public consultation, most stakeholders support the full integration of renewable
energy sources into the market, e.g. through full balancing obligations for renewables,
phasing-out priority dispatch and removing subsidies during negative price periods. Many
stakeholders note that the regulatory framework should enable RES E to participate in the
market, e.g. by adapting gate closure times and aligning product specifications. A number
of respondents also underline the need to support the development of aggregators by
removing obstacles for their activity to allow full market participation of renewables. The
approach chosen in the State aid guidelines found broad support by most stakeholders.
Wind Europe's predecessor EWEA submitted
26
that in 14 out of 18 Member States, wind
generators were already balancing responsible in financial or legal terms, generally subject
to the same rules as conventional generation. However, in some Member States, balancing
costs for renewable generators appeared discriminatorily high. Important considerations
for wind generators to accept balancing responsibility were, for EWEA: (i) the existence
of a functioning intra-day and balancing market, (ii) balancing market arrangements
providing for the participation of wind power generators, as e.g. shorter gate closure time
and procurement timeframes, (iii) market mechanisms that properly value the provision of
non-frequency ancillary services for all market participants including wind power, (iv) a
satisfactory level of market transparency and proper market monitoring, (v) sophisticated
forecast methods in place in the power system and (vi) the necessary transmission
infrastructure. While forecast methods should be developed by the market and cannot be
provided directly in policy (which can only give incentives for such methods to be
improved and used), the market design initiative aims at achieving all these points.
In its consultation of national TSOs, ENTSO-E also adressed questions on balancing
responsibility. TSOs in five Member States answered that after introduction of balancing
26
http://www.ewea.org/fileadmin/files/library/publications/position-papers/EWEA-position-paper-
balancing-responsibility-and-costs.pdf
26
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responsibilities, RES E generators were more motivated to conclude energy production
contracts which are close to the real production in each market time unit; for four Member
States, better forecasts were used by RES E generators. 1 TSO provided figures according
to which the average hourly imbalance of PV installations improved from 11.2 % in 2010
to 7.0 % in March 2016, and the average hourly imbalance of wind improved from 11.1 %
to 7.4 % over the same period.
27
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1.3. RES E access to provision of non-frequency ancillary services
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Summary table
Objective: transparent, non-discriminatory and market based framework for non-frequency ancillary services
Option 0
Option 1
Option 2
BAU
Description
Description
Different requirements, awarding procedures and Set out EU rules for a transparent, non-discriminatory and Set out broad guidelines and principles for Member States for the
remuneration schemes are currently used across market based framework to the provision of non-frequency adoption of transparent, non-discriminatory and market based
Member States. Rules and procedures are often tailored ancillary services that allows different market players framework to the provision of non-frequency ancillary services.
to conventional generators and do not always abide to /technology providers to compete on a level playing field.
transparency, non-discrimination. However increased
penetration of RES displaces conventional generation
and reduces the supply of these services.
Stronger enforcement
Pro
Pro
Provisions containing reference to transparency, non- Accelerate adoption in Member States of provisions that Sets the general direction and boundaries for Member States
discrimination are contained in the Third Package. facilitate the participation of RES E to ancillary services as without being too prescriptive.
However, there is nothing specific to the context of non- technical capabilities of RES E and other new technologies is Allows gradual phase-in of services based on local/regional needs
frequency ancillary services.
available, main hurdle is regulatory framework.
and best practices.
Clear regulatory landscape can trigger new revenue streams
and business models for generation assets.
Con
Con
Resistance
from
Member
States
and
national Possibility of uneven regulatory and therefore market developments
authorities/operators due to the local/regional character of depending on how fast Member States act. This creates uncertain
non-frequency ancillary services provided.
prospects for businesses slowing down RES E penetration.
Little previous experience of best practices and unclear how
to monitor these services at DSO level where most RES E is
connected.
Most suitable option(s): Option 2
is best suited at the current stage of development of the internal electricity market. Ancillary services are currently procured and sometimes used in very
different manners in different Member States, Furthermore, new services are being developped and new market actors (e.g. batteries) are quickly developing. Setting out detailed rules required
for full harmonisation would thus preclude unknown future developments in this area, which currently is subject to almost no harmonisation.
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Description of the baseline
The delivery of
frequency
related ancillary services by RES E assets is partly covered by
the Balancing Guideline.
Non-frequency
ancillary services are services procured or mandated by TSOs that support
the electricity network, such as voltage support, short circuit power, black start capability,
synthetic inertia or congestion management. They are in most cases supplied by electricity
generators, but can in some cases also be supplied by demand facilities, electricity storage
or network equipment.
Currently, the procurement of non-frequency anciliary services is not regulated at EU-
level. The situation in Member States for the provision of
non-frequency
ancillary services
is determined by national grid codes that
inter alia
specify the rules for connection of
generation assets to the electric network infrastructure. Grid codes are evolving
continuously, but a snapshot taken recently through studies funded by the European
Commission
27
, a survey commissioned by ENTSO-E
28
and by examining the actual
national grid codes, reveals that several approaches are considered in Europe across more
than a dozen Member States (as well as Norway and Switzerland) surveyed. The snapshot,
summarized in Figures 1 to 3, focuses only on the provision of reactive power, i.e. voltage
related ancillary services, one of the most important non-frequency ancillary services. It is
important to point out that the overview is partial and does not cover all specific
arrangements TSOs might have. For instance in Denmark, these services are not generally
remunerated, however in certain periods of the year when thermal plants are not operating,
these services are remunerated to guarantee sufficient supply.
27
"REserviceS project"
(2014) Intelligent Energy Europe programme,
http://www.reservices-project.eu/
28
"Survey on Ancillary Services Procurement and Electricity Balancing Market Design"
(2015) ENTSO-
E,
https://www.entsoe.eu/Documents/Publications/Market%20Committee%20publications/WGAS%20Su
rvey_04.05.2016_final_publication_v2.pdf?Web=1
31
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Figure 1: Grid code requirements for generators on reactive power
Source: National grid codes, ENTSO-E survey, REserviceS project
Figure 2: Procurement procedure of reactive power
Source: National grid codes, ENTSO-E survey, REserviceS project
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Figure 3: Remuneration of reactive power delivery
Source: National grid codes, ENTSO-E survey, REserviceS project
Currently the practises with regard to requirements, procurement and renumeration of non-
frequency anciliary services can be summarised as follows:
-
Requirements: most Member States demand mandatory provision from
conventional generators and in some cases specific provisions are considered for
RES E, mostly wind. The latter approach is in line with the Commission Regulation
(EU) 2016/631 establishing a network code on requirements for grid connection of
generators ('RfG');
Procurement: a majority of Member States procure these services through bilateral
agreements and only in a small minority of Member States market based tenders
are used. In other Member States both bilateral agreements and market based
tenders are used;
Remuneration: about half of the surveyed Member States do not have a mechanism
to remunerate the service, the other half does remunerate them either by capability,
utilisation or a combination of both. In some Member States, a bonus is given to
RES E for upgrading the infrastructure.
Deficiencies of the current legislation
The current EU regulatory framework defines in Article 12 lit. d) of the Electricity
Directive the role of the TSO: it includes ensuring the availability of all necessary ancillary
services. However, there is nothing specific with regard to non-frequency ancillary
services. The RfG specifies extensively requirements for the provision of reactive power
by different power modules. However, it does neither address the procedures by which
such services should be awarded (e.g; a market based mechanism), nor whether they should
be remunerated (as such or on the basis of what criteria e.g. capacity, utilisation or a
combination thereof). Additionally, the RfG is not likely to lead to an efficient deployment
of reactive power capability on the territory as voltage support services have a geographical
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-
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dimension and need to be provided in specific locations. This might lead to an oversupply
of reactive power capability (with associated increased costs born by the generators) and
at the same time underutilization of installed capability because they are not suitably
located. The System Operation Guideline aims at ensuring that TSOs use market-based
mechanisms as far as possible to ensure network security and stability, but does not
articulate further this high level principle.
The current legislation is insufficient and needs to be adapted to trends observed in the
market where studies project that the demand for non-frequency ancillary services across
Europe will increase over the coming decades, mainly because of increased RES E
penetration. A technical and economical study by Électricité de France (EDF)
29
concluded
that
"it is essential that variable RES production which is displacing conventional
generation is also able to contribute to the provision of ancillary services and also
potentially provide new services (e.g. inertia)".
A study commissioned by the German
Energy Agency Dena
30
found that
"due to increasing transport distances and international
power transit, the demand for reactive power in the transmission grid will increase
significantly by 2030."
Presentation of the options
Option 0 - BAU
In a business-as-usual scenario, non-frequency ancillary services are mainly provided by
large conventional generators. Although those services are currently not remunerated in all
Member States, TSOs would need those generators to run even if not profitable. Therefore
such generators would request additional revenues. This scenario prevent the access to
additional revenue streams for new types of generation assets, mainly being RES E.
Since RES E are displacing conventional generation assets, the supply of these services is
becoming scarcer. As a result, generation from RES E would be curtailed at certain times
to guarantee the safe operation of the electric network. This would likely slow down the
deployment of RES E and affect negatively the achievement of the European wide
renewable energy consumption targets by 2020 and 2030 and related climate goals.
Option 0+: Non-regulatory approach.
The Third Package does not address the provision of non-frequency ancillary services in a
way that could be used to enforce existing legislation stronger. Voluntary cooperation does
not provide the necessary minimum degree of harmonization and legal certainty to allow
for efficient cross-border trade. Even where non-frequency anciliary services have to be
provided on a local level, the provision of and revenues from these services can have a
significant impact on the competitiveness of electricity generation, which competes cross-
border.
29
30
"Technical and Economic analysis of the European Electricity System with 60% RES"
(2015) Alain
Burtin & Vera Silva,
http://www.energypost.eu/wp-content/uploads/2015/06/EDF-study-for-download-
on-EP.pdf
"Dena Ancillary Services Study 2030"
(2014) German Energy Agency,
http://www.dena.de/en/projects/energy-systems/dena-ancillary-services-study-2030.html
34
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Option 1 - EU rules setting out a framework for a transparent, non-discriminatory, market
based framework
This option would imply setting EU wide harmonized rules in EU legislation on
requirements of generators for connection to the grid, on specifications and procurements
of products to ensure a level-playing field and fair remuneration of these services. This
would encounter a number of issues: even though the provision of non-frequency ancillary
services is necessary to run a European wide electricity market, due to the local/regional
character of these services, optimal solutions may vary across Member States.
Additionally, it would require the coordination of both transmission and distribution
system operators as a large fraction of RES E is installed at the distribution level. These
services are not generally remunerated at lower voltage levels and no clear framework is
yet available on how to regulate these services. Finally, there are still significant challenges
for market based integration of ancillary services from RES E due to limitations of
predictability of energy output.
Option 2 - Guidelines setting out the principles for the adoption of a transparent, non-
discriminatory, market based framework.
The aim is to provide a sound basis for the development of a non-discriminatory,
transparent and market based access to non-frequency ancillary services by RES E and to
allow the gradual phase-in of services based on local/regional needs and best practices.
This is a pre-requisite for a cost efficient allocation of resources to provide the necessary
supply of non-frequency ancillary services. The measures should be articulated along the
following main lines:
-
ensure that the regulatory requirements for the provision of these services are
rational with respect to the expected needs (both in terms of quantity and location)
and non-discriminatory with respect to different assets capable of providing the
service.
bring transparency to the way ancillary services are procured, for instance through
market-based tenders or auctions and allow sufficient flexibility in the process to
accommodate bids from assets with different technical characteristics;
promote mechanisms for remuneration by system operators;
consult stakeholders when establishing new rules to make sure all assets can
participate to these services while providing support for safe grid operation.
-
-
-
These measures are also conducive to a higher penetration of RES E in the electricity
network and could be further developed in a dedicated network code.
Comparison of the options
The BAU scenario would not be effective in designing a level-playing field for a non-
discriminatory, transparent and market based access to non-frequency ancillary services
and in achieving the objectives of increasingly integrated RES E in a European electricity
market. It would also be an obstacle for further increase of RES E in the generation mix
with a potential negative impact on the achievement of the 2030 targets. In the current
situation, where ancillary services are provided by conventional generators, curtailment of
RES E is required at times to assure the availability of generation assets capable of
providing ancillary services (so-called "must run"). The decision to keep these resources
online is not based on economic assessments, but only on operational considerations for a
safe operation of the grid. Such constraint would not exist or not to the same extent if RES
35
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E resources would be used to their fullest potential to provide non-frequency ancillary
services.
Options 1 and 2 would be more effective in providing a non-discriminatory, transparent
and market-based environment for RES E and new technologies to offer and compete for
the provision of non-frequency ancillary services. Companies, especially owners of RES
E assets would benefit from additional revenue streams from ancillary markets.
Extrapolating the European wide market size for non-frequency ancillary services from
national markets (typically in the range of tens of millions of euros) puts it roughly in the
range of a few billion euros.
In addition, the investment outlook for additional power plants would be better for owners
of RES E assets. Taking Ireland as a best practice case, regulators and TSOs are
redesigning the ancillary service market in such a way that RES E can participate. It
requires introducing new services and allowing these services to be remunerated. This has
the additional benefit that the electricity generation share of RES E in such a redesigned
market can be higher without compromising the safe operation of the grid and allows
system operators to make efficiency gains: the Irish All Island TSOs compared the
estimated costs of enhancing the operational capabilities of ancillary services with the
benefits of lower market prices coming from a larger share of wind energy generation.
They concluded that the benefit outwheighted the costs already at System Non-
Synchronous Penetration levels below 50%
31
.
Based on the studies and sources mentioned in this and other Sections of this annexe, little
uncertainty exists about the benefits of more transparent provision of ancillary services,
one where RES E could participate. For certain services, especially those that have a
limited geographical scope, it is unclear if and how liquid markets could be established,
with regulated cost+ payments being a possible alternative.
The second Option is preferred over the first one, because at this moment there is not
enough evidence to support European wide harmonized rules for non-frequency ancillary
services. New services are being developed and new market players are emerging. The
first option could preclude unknown future developments in this area, whereas the second
option allows the gradual phase-in of services based on local/regional needs and best
practices.
Subsidiarity
Even though non-frequency anciliary services, such as voltage related ancillary services
have a local character, it does not prevent action through the market design initiative. The
efficient provision of these services is a critical enabler of an integrated European
electricity market and of higher RES E penetration. Also, the assets that provide non-
frequency ancillary services are largely the same ones providing frequency-related
services: a local problem due to voltage stability could have implications for the provision
of frequency-related services and the stability of the grid at a European level as a whole.
Finally, the assets providing ancillary services are generally competing in other markets
31
"Onshore wind supporting the Irish grid"
(2013) Andrej Gubina,
http://www.reservices-project.eu/wp-
content/uploads/D5.1-REserviceS-Ireland-case-study-Final.pdf
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with a larger geographical scope, including the day ahead and intraday electricity markets.
Conditions on voltage control thus have an impact on cross-border competition in
electricity markets.
Stakeholders' opinions
RES E
32
and demand response
33
industry associations and owners of storage
34
assets assert
the technical availability to provide non-frequency ancillary services, but expose
difficulties accessing the market because of non-transparent rules for contracting,
minimum product size and other product specifications, as well as procurement lead times.
Younicos, a storage provider, states that
"storage is not defined in regulatory framework
on national or EU level, creating uncertainty on market access and creating uncertainty
on ownership roles."
Similarly, the Association of European Manufacturers of automotive,
industrial and energy storage batteries (EUROBAT), calls for a legislative definition of
storage which allows system operators to own and operate battery storage. The association
calls for the value of services offered by storage systems, including voltage control,
frequency control and ramp control, to be financially recognized. Anciliary services should
thus be compensated
35
. The European Wind Energy Association points out that the reactive
power requirements at low active power set points imposed on RES E in the frame of the
RfG code could potentially have a substantial negative impact on the investment costs of
new wind power plants..
Energinet.dk considers increased competition for the supply of ancillary services
"as a part
of the continuous development of the energy only market with the objective to create clear
price signals and creating socio economic benefits and security of supply on short and
long run".
Geographical requirements for delivery of ancillary services is a challenge in
developing these markets as well as the fact that grid components such as
"synchronous
compensators and HVDC VSC-convertors have a potential to deliver system supporting
services in competition with commercial power plants. This development demands
transparency in the procurement process to secure optimal planning, operations and
investments"
36
.
Two joint papers by Statkraft and Dong Energy point out that
"in the past, system services
have played a marginal role in total economics of power plants. In the future, however,
system services will be more important for the individual plant and the value (balance of
32
"Balancing responsibility and costs of wind power plants"
(2015) European Wind Energy Association,
http://www.ewea.org/fileadmin/files/library/publications/position-papers/EWEA-position-paper-
balancing-responsibility-and-costs.pdf
33
"Mapping Demand Response in Europe today"
(2015) Smart Energy Demand Coalition,
http://www.smartenergydemand.eu/wp-content/uploads/2015/09/Mapping-Demand-Response-in-
Europe-Today-2015.pdf
34
"Technical and regulatory aspects of the provision of ancillary services by battery storage"
(2015)
Younicos
35
"Battery Energy Storage in the EU: barriers, opportunities, services and benefits"
(2016) EUROBAT,
http://www.eurobat.org/sites/default/files/eurobat_batteryenergystorage_web.pdf p.30.
36
"Markets for ancillary and system supporting services in Denmark" (2016) Energinet.dk
37
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supply and demand of these services) to the system are likely to be markedly higher",
and
that
"requirements put into tenders are crucial for the outcome".
37
37
"Does the wholesale electricity market design need more products, or more control?"
Part 1 (2015) &
Part 2 (2016) Dong Energy & Statkraft
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2. D
ETAILED MEASURES ASSESSED UNDER
P
ROBLEM
A
REA
I,
S
TRENGTHENING SHORT
-
TERM MARKETS
OPTION
1(
B
)
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2.1. Reserves sizing and procurement
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Summary table
Objective:
define areas wider than national borders for sizing and procurement of balancing reserves
Option 0: business as usual
Option 1: national sizing and procurement
Option 2: regional sizing and procurement of
of balancing reserves on daily basis
balancing reserves
The baseline scenario consists of
This option involves the setup of a binding
a smooth implementation of the
This option consists in developing a
regulation requiring TSOs to use regional
binding regulation that would require TSOs platforms for the procurement of balancing
Balancing Guideline. Existing
on-going experiences will
to size their balancing reserves on daily
reserves. Therefore this option foresees the
probablistic methodologies. Daily
remain and be free to develop
implementation of an optimisation process for
further, if so decided. However,
calculation allows procuring lower
the allocation of transmission capacity between
sizing and procurement of
balancing reserves and, together with daily
energy and balancing markets, which then
balancing reserves will mainly
procurement, enables participation of
implies procuring reserves only a day ahead of
remain national as foreseen in
renewable energy sources and demand
real time
.
the Balancing Guideline.
response.
This option would result in a higher level of
This option foressees separate procurement
coordination between European TSOs, but still
of all type of reserves between upward (i.e.
Active participation in the
relies on the concept of local responsibilities of
Balancing Stakeholder Group
increasing power output) and downward
individual balancing zones and remains
could ensure stronger
(i.e. reducing power output; offering
compatible with current operational security
enforcement of the Balancing
demand reduction) products.
principles.
Guideline.
Pro
–
optimal national sizing and
Pro
–regional
areas for sizing and procurement
procurement of balancing reserves
of balancing reserves
Option 3: European sizing and procurement of
balancing reserves
This option would have a major impact on the
current design of system operation procedures
and responsibilities and current operational
security principles. A supranational
independent system operator ('EU ISO') would
be responsible for sizing and procuring
balancing reserves, cooperating with national
TSOs. This would enable TSOs to reduce the
security margin on transmission lines, thus
offering more cross-zonal transmission
capacity to the market and allowing for
additional cross-zonal exchanges and sharing
of balancing capacity.
Description
Pros
Pro
–
single European balancing zone
Con
–
extensive standardisation through
replacement of national systems, difficult and
costly implementation
Most suitable option(s) Option 2.
Sizing and procurement of balancing reserves across borders require firm transmission cross-zonal capacity. Such reservation might be limited by the
physical topology of the European grid. Therefore, in order to reap the full potential of sharing and exchanging balancing capacity across borders, the regional approach in Option 2 is the
preferred option.
Cons
Con
–
no cross-border optimisation of
balancing reserves
Con
–
balancing zones still based on national
borders but cross-border optimisation possible
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Description of the baseline
Balancing refers to the situation after markets have closed (gate closure) in which a TSO
acts to ensure that demand is equal to supply. A number of stakeholders are responsible
for organising the electricity balancing market:
-
Transmission system operators ('TSOs') keep the overall supply and demand in balance
in physical terms at any given point in time. This balance guarantees the secure
operation of the electricity grid at a constant frequency of 50 Hertz.
-
Balance responsible parties ('BRPs') such as producers and suppliers; keep their
individual supply and demand in balance in commercial terms. Achieving this requires
the development of well-functioning and liquid markets. BRPs need to be able to trade
via forward markets and at the day-ahead stage. They also need to be able to fine-tune
their position within the same trading day (e.g. when wind forecasts or market positions
change).
-
Balancing service providers ('BSPs') such as generators, storage or demand facilities,
balance-out unforeseen fluctuations on the electricity grid by rapidly increasing or
reducing their power output. BSPs receive a capacity payment for being available when
markets have closed ('balancing capacity' also referred to as 'balancing reserve') and an
energy payment when activated by the TSO in the balancing market ('balancing
energy'). Payments for balancing capacity are often socialized via the transmission
network tariffs, whereas payments for balancing energy usually shape the price that
BRPs who are out of balance have to pay ('imbalance price').
Currently, national balancing markets in Europe have significantly different market
designs and are operated according to different principles
38
. To achieve efficiency gains
through a genuine European balancing market, it is essential to provide a set of common
principles. As one can expect the adoption of the Balancing Guideline in 2017, it is possible
to agree on the baseline, which can be built upon in the market design initiative.
The Balancing Guideline covers, in particular:
-
Standardisation of balancing products
39
used by TSOs to maintain their system in
balance. The starting point is a situation where, in Europe, the number of balancing
products is estimated at some hundred. TSOs will have to reduce this number as much
as possible to create a harmonised competitive market.
-
Merit order activation of balancing energy based on European platforms, i.e.
operational within 4 years after the entry into force, where all TSOs will have access
while taking into account cross-zonal transmission capacity available or released after
intraday gate closure.
-
Single marginal pricing ('pay-as-cleared') which reflects scarcity for the remuneration
of the participants in the balancing market (i.e. the payment that a participant receives
for providing balancing energy to be the same payment as the imbalance price). Thus
being individually in imbalance but contrary to the imbalance of the system as a whole,
38
39
ENTSO-E survey on ancillary services, May 2016:
https://www.entsoe.eu/Documents/Publications/Market%20Committee%20publications/WGAS%20Su
rvey_04.05.2016_final_publication_v2.pdf?Web=1
The term "product" refers to different balancing services which can be traded, such as the provision of
balancing energy with different speeds of delivery.
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thus helping the system as a whole to stay balanced, gets rewarded rather than
penalized.
-
Harmonisation of the length of the imbalance settlement periods ('ISP' i.e. the time over
which it is measured whether BRPs stay in balance, i.e. they did not sell more
electricity than they produced). Trading products are generally not shorter than, but
can be multiples of ISP. The length of the ISP is thus of relevance for all market
timeframes and not just for the balancing market. In cross-border trade, the biggest
common ISP has to be used. Thus, the smallest trading product across Europe is
currently 60 minutes which corresponds to the length of the longest ISP across Member
States. However, where two Member States have shorter ISPs, shorter products can be
traded across their border (e.g. 30 minutes between France and Germany). To increase
the trade of short products, the Balancing Guideline proposes a shift to harmonized 15
minutes ISPs
40
.
The Balancing Guideline also provides the baseline for integrating renewable energy
sources and demand response in the balancing market, in particular:
-
Balancing energy gate closure time (i.e. the point in time after which there can be no
more balancing energy offers from BSPs) as close as possible to physical delivery, and
at least after intraday cross-zonal gate closure (thus a maximum of 60 minutes before
real time). Shorter gate closure time allows wind or PV generators and demand
response aggregators to update their forecast and to offer remaining energy to the
electricity balancing market.
-
Possibility to offer balancing energy without a balancing capacity contract. The
procurement timeframes for balancing capacity have generally long lead times for
which wind or PV power producers and demand response aggregators cannot secure
firm capacity.
-
Shorter procurement timeframes for balancing capacity (close to real time).
It would be, however, out of the scope of the Balancing Guideline to aim for full
harmonization of the currently very diverse balancing markets. The Balancing Guideline
includes many exemptions (e.g. central dispatch systems, procurement rules for balancing
capacity) and possible derogations (e.g. dual pricing as opposed to single marginal
pricing). It is therefore essential that all national balancing markets adhere to a minimal set
of common principles.
In addition, balancing reserves are currently mainly sized and procured by TSOs on a
national level (except for the Nordic countries and the Iberian Peninsula). This contrasts
with the increasing demand for balancing reserves across Europe over the coming decades
which is mainly due to large-scale cross-border flows and high volumes of variable RES
E generation. Most of the TSOs are sizing their balancing reserves based on potential
outages of HVDC interconnectors and forecast errors of renewable energy sources. Despite
40
"Frontier
Economics report on the harmonisation of the imbalance settlement period",
April 2016
https://www.entsoe.eu/Documents/Network%20codes%20documents/Implementation/CBA_ISP/ISP_
CBA_Final_report_29-04-2016_v4.1.pdf
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trends observed in the market (see below figure from ELIA, the Belgian TSO)
41
on the
evolution of balancing reserves needs from 2013 to 2018, no significant binding
harmonisation is achieved on this subject in the Balancing Guideline.
Graph 1: Interpolated ranges for the volume of reserves needed between 2013 and
2018
Source: Belgian TSO report on the evolution of ancillary services needs to balance the Belgian control
areas towards 2018, pp. 32)
In their Market Monitoring report 2014
42
, ACER points out that in most European markets,
the procurement of balancing capacity represents the largest proportion of the overall costs
of balancing. The excessive weight of the balancing capacity procurement costs may
suggest that the procurement of balancing capacity is not always optimised. ACER
emphasis the importance of optimising the procurement costs of balancing capacity,
including separate procurement of upward and downward balancing capacity and shorter
procurement timeframes.
41
42
Belgian TSO report on the evolution of ancillary services need to balance the Belgian control area
towards 2018, May 2013
http://www.elia.be/~/media/files/Elia/Grid-data/Balancing/Reserves-Study-2018.pdf
"Market Monitoring Report 2014"
(2015) ACER, pp. 210.
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Graph 2: Overall costs of balancing (capacity and energy) and imbalance charges
over national electricity demand in a selection of European markets
–
2014
(euros/MWh)
Source:
"Market
Monitoring Report 2014"
(2015) ACER,
pp. 209
Moreover, because only flexible generation assets can provide balancing reserves,
balancing markets tend not to be very competitive. Balancing markets are regularly rather
concentrated on the supply side as only assets able to adjust production or consumption
fast can participate. In their Market Monitoring report 2014, ACER also illustrates the very
high level of concentration in the procurement of balancing capacity.
Graph 3: Level of concentration in the provision of balancing services from automatic
Frequency Restoration Reserves (capacity and energy) for a selection of Member
States
–
2014 (%)
Source:
"Market
Monitoring Report 2014" (2015) ACER, pp. 207
Integrating balancing markets will increase competition and hence will save overall costs.
These costs are largely determined by the size of the network area for which the balancing
reserves are being procured (also referred to as 'balancing zone' or 'load-frequency control
block') and the frequency with which this is done. The size of the reserves that need to be
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set aside depends on the size of unforeseen events within a given balancing zone. Larger
zones across TSO-control areas (effectively across Member States) will result in lower
total balancing reserve requirements and reduce significantly the need for back-up
generation, as the risks to be covered are smaller than with a simple addition of the risks
of two small zones. To this end, a limited number of wider balancing zones should be
defined by the needs of the network rather than national borders.
Deficiencies of the current legislation (see also Section 7.4.2 of the evaluation)
Recitals and provisions containing reference to transparent, non-discriminatory and
market-based procedures for the procurement of balancing capacity are contained in the
Electricity Directive. However, there is nothing more specific to the procurement rules. As
part of the regional cooperation of TSOs, Article 12.2 of the Electricity Regulation refers
to the integration of balancing and reserve power mechanism. However, no further details
are being developed concerning the sizing of balancing reserves at regional level.
The Guidelines on System Operation (approved in Comitology on 4
th
of May 2016)
harmonise terms, methodologies and procedures for sizing balancing reserves, but it is
expected that balancing zones (or LFC Blocks) will remain unchanged and mainly based
on national borders (except for Nordic countries and Spain-Portugal) as illustrated below.
Figure 1: Synchronous Areas, LFC Blocks (or balancing zones) and LFC Areas
Source: ENTSO-E supporting document for the Network Code on Load-Frequency Control and Reserves,
2013, pp. 42
The Balancing Guideline (not yet approved in Comitology) intends to set out rules for the
procurement of balancing capacity, the activation of balancing energy and the financial
settlement of BRPs. It would also require the development of a harmonised methodology
for the reservation of cross-zonal transmission capacity for balancing purposes. However
sharing and exchange of balancing capacity would not be mandatory under the Balancing
Guideline but encouraged.
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Presentation of the options
Option 0 - BAU
The baseline scenario consists of a smooth implementation of the Balancing Guideline
where sharing and exchange of balancing capacity are not mandatory. In this way, the
existing on-going experiences (such as the regional sizing and procurement of balancing
reserves in the Nordic countries and the Iberian Peninsula) will remain and be free to
develop further and integrate, if so decided by the participating parties. Isolated and likely
incompatible projects may be implemented across Europe.
Procurement arrangements such as shorter contracting period close to real time should be
enforced in line with the development of a methodology for the reservation of cross-zonal
transmission capacity for balancing purposes.
Option 0+: Non-regulatory approach
The Third Package does not address the provision of regional sizing and procurement of
balancing reserves in a way that could be used to stronger enforce existing legislation.
Specific parts dealing with transparency, non-discrimination and market based rules can
be found in the Article 15 of the Electricity Directive. Others parts dealing with the regional
cooperation of TSOs on balancing and the optimal allocation of capacity across timeframes
can be found in Article 12.2 and Annex 1.2.6 of the Electricity Regulation.
Voluntary cooperations between TSOs for sharing and exchaning balancing capacity could
be further supported thanks to an active participation in the Balancing Stakeholder Group
established by ACER and ENTSO-E for an early implementation of the Balancing
Guideline. However no mandatory provisions in the Balancing Guideline request TSOs to
size and procure reserves at regional level.
Option 1
–
National sizing and procurement of balancing reserves on a daily basis
This option consists in developing a binding regulation that would require TSOs to size
their balancing reserves on daily probabilistic methodologies (i.e. based on different
variables such as RES E generation forecasts, load fluctuations and outage statistics). This
method is opposed to a deterministic approach which consists of sizing the balancing
reserves on the value of the single largest expected generation incident. Daily calculation
allows procuring lower balancing reserves and, together with daily procurement, enables
participation of renewable energy sources and demand response.
Shorter procurement timeframes for balancing capacity facilitate the participation of wind
generators and demand response aggregators which cannot secure firm capacity over long
lead times, or storage operators, which do not have to guarantee specific amounts of energy
stored over long periods. This option foresees separate procurement of all types of reserves
between upward (i.e. increasing power output; offering demand reduction) and downward
(i.e. reducing power output; offering demand increase) products.
Option 2
–
Regional sizing and procurement of balancing reserves
This option involves the set up of a European binding regulation requiring TSOs to use
regional platforms for the procurement of balancing reserves. Mandatory sharing and
exchange of balancing capacity requires firm cross-zonal transmission capacity. Therefore
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this option foresees the development of an optimisation process for the allocation of
transmission capacity between energy and balancing markets, which then implies
procuring reserves only a day ahead of real time.
This option thus has the focus on a more integrated approach on the sizing and procurement
of balancing reserves themselves. Mandatory regional procurement of balancing reserves
would require changing and harmonizing adjacent business and related operational
processes. Mandatory regional sizing of balancing reserves might have an impact on
system operation procedures and responsibilities, at least procedurally shifting security of
supply-related tasks (such as system's state analysis) to a supranational level (possibly to
newly-established regional operational centres ('ROCs'), see also Section 2.3).
TSOs would still be responsible for real-time activation of the balancing capacity procured;
however they would only have access to the regional platforms for the procurement of
balancing capacity which would assume harmonized procurement timeframes and
centralised optimisation algorithm requiring firm cross-border transmission capacity to be
available. Balancing reserves would be estimated on a daily basis and based on
probabilistic methodologies.
Option 3
–
European sizing and procurement of balancing reserves
This option would result in a significant evolution of the current design in which European
electricity systems are operated. This would have a major impact on the current design of
system operation procedures and responsibilities.
This option involves setting up a binding European framework to ensure that all Member
States implement a single market design for sizing and procurement of balancing reserves.
A supranational independent system operator ('EU ISO') would be responsible for sizing
and procurement of balancing reserves, cooperating with national TSOs. This would
enable TSOs to reduce the security margin on transmission lines, thus offering more
transmission capacity to the market and allowing for additional sharing and exchanges of
balancing capacity.
Comparison of the options
Economic impacts
All three options can capture some of the potential social welfare opportunities. Option 3
would be the most effective in achieving an optimal sizing and procurement of balancing
reserves at European level. However, it might not be feasible as sharing and exchanges of
balancing capacity require firm cross-zonal transmission capacity. Such reservation might
be limited by the physical topology of the European grid (e.g. geographical distribution of
the balancing reserves to maintain operational security
43
). Option 1, which foresees daily
sizing of balancing reserves at national level and separate procurement of downward and
upward balancing capacity, would result in an increased participation of wind power
producers and demand response aggregators in the balancing market. While the
improvements of national rules regarding sizing and procurement of balancing reserves
43
ENTSO-E supporting document for the Network Code on Load-Frequency Control and Reserves, 2013,
pp. 75
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would allow savings around EUR 1.8 billion, it would not reap the full potential of cross-
border exchanges. Daily sizing and procurement of balancing reserves could therefore be
optimally performed at regional level. The preferred option is thus Option 2, which brings
savings of around EUR 3.4 billion.
Table 1: Economic impacts by option
Balancing reserves needs (GW)
Balancing reserves needs reduction
Annual savings (EUR billion)
Source: METIS
BAU
53.4
-
-
Option 1
52.1
3%
1.8
Option 2
29.9
44%
3.4
Option 3
17.1
68%
4.5
Regulatory impact
The costs of sizing and procuring balancing reserves at regional level are mainly linked to
the possibility to add a task to the newly-established regional operational centres ('ROCs')
(see also Section 2.3 of the present annexes to the impact assessment). System state
analysis would have to be performed on a daily basis and regional level by the ROCs,
together with the setting-up of regional plaforms for the procurement of balancing reserves.
The option entailing the smallest change (Option 1) involves costs significantly less than
the other two options. Option 2 is likely to be more expensive as a result of the additional
tasks to ROCs and the setting-up of several new platforms for the exchange or sharing of
balancing reserves.
Subsidiarity
The subsidiarity principle is fulfilled given that the EU is best placed to provide for a
harmonised EU framework for common sizing and procurement of balancing reserves.
Most Member States currently take national approaches to size and procure balancing
reserves including often not allowing for foreign participation. As common sizing and
procurement of balancing reserves requires neighbouring TSOs' and NRAs' full
cooperation, individual Member States might not be able to deliver a workable system or
only provide suboptimal solutions.
Providing mandatory regional sizing and procurement of balancing reserves would be also
in line with the proportionality principle given that it aims at preserving the properties of
market coupling and ensuring that the distortions of uncoordinated national balancing
mechanisms are corrected and the internal market is able to deliver the benefits to
consumers.
Stakeholders' opinions
Most respondents from the Market Design consultation agreed with the need to speed up
the development of integrated short-term (balancing and intraday) markets. A significant
number of stakeholders argue that there is a need for legal measures, in addition to the
technical network codes and guidelines under development, to speed up the development
of cross-border balancing markets, and provide for clear legal principles on non-
discriminatory participation in these markets.
In ENTSO-E's view a parallel harmonization of balancing energy and balancing capacity
procedures would lead to unreasonably high effort for TSOs and would introduce
additional uncertainty and insecurity for the operation of the electricity system if made
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mandatory. However ENTSO-E and ACER recognise that common cross-border
procurement of reserves is a good target in the long-term.
The March 2016 Electricity Regulatory Forum (the "Florence Forum"), a forum for
stakeholders to engage on wholesale market regulatory issues, made the following relevant
conclusion:
"The Forum stresses the importance of balancing markets for a well-integrated and
functioning EU internal energy market. It encourages the Commission to swiftly bring the
draft Balancing Guideline to Member States for discussion, ideally before the summer,
with a view to reaching agreeement in autumn this year. It considers, however, that there
may still be improvements needed and ask the Commission to consider the provisions of
the draft Guideline carefully before presenting a formal proposal.
The Forum supports the view that further steps are needed beyond agreement and
implementation of the Balancing Guideline. In particuler, further efforts should be made
on coordinated sizing and cross-border sharing of reserve capacity. It invites the
Commission to develop proposals as part of the energy market design initiative, if the
impact assessment demonstrates a positive cost-benefit, which also ensure the effectiveness
of intraday markets."
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2.2. Removing distortions for liquid short-term markets
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Summary table
Objective: to remove any barriers that exist to liquid short-term markets, specifically in the intraday timeframe, and to ensure distortions are minimised.
Option 0
Business as usual
Local markets mostly unregulated, allowing for national
differences, but affected by the arrangements for cross-
border intraday and day-ahead market coupling.
Option 1
Fully harmonise all arrangements in local
markets.
Option 2
Selected harmonisation, specifically on issues relating to gate closure
times and products.
Description
Stronger enforcement and volunatry cooperation
There is limited legilsation to enforce and voluntary
cooperation would not provide certainty to the market.
Simplest approach, and allows the cross-border
arrangements to affect local market arrangements. Likely to
see a degree of harmonisation over time.
Would minimise distortions, with very limited
opportunity for deviation.
Targets issues that are particularly important for maximising liquidity
of short-term markets and allows for participation of demand response
and small scale RES.
May still be difficult to implement in some Member States with
implication on how the system is managed
–
central dispatch systems
could, in particular, be impacted by shorter gate closure time.
Pros
Differences in national markets will remain that can act as a
barrier.
Extremely complex; even the cross-border
arrangements have not yet been decided and
need significant work from experts.
Additional benefit unclear.
Most suitable option(s): Option 2
–
Provides a proportionate response targeting those issues of most relevance.
Cons
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Description of the baseline
Intraday markets usually open several hours before the day of delivery and allow market
participants to trade energy products i.e. discrete quantities of energy for a set amount of
time - close to real time and as short as five minutes before delivery.
Liquid intraday markets will form a critical part of a European energy market that is able
to cost-effectively accommodate an increasing share of variable renewable sources, allow
for more demand-side participation, and allow for energy prices to reflect scarcity.
"Liquidity is a measure of the ability to buy or sell a product
–
such as electricity -
without causing a major change in its price and without incurring significant
transaction costs. An important feature of a liquid market is the presence of a large
number of buyers and sellers willing to transact at all times"
44
.
Maximising liquidity in the intraday market will increase competitive pressure, increase
confidence in the resulting energy prices, and allow adjustment of positions close to real
time, thus reducing the need for TSO actions in the balancing timeframes (although it
should be noted that this will not by itself reduce the need for remedial actions by TSOs to
address congestion in internal grids).
-
The more variable source of renewable generation in the EU energy mix, the more
impact of errors in forecasting of weather and demand. Allowing close-to-real-time
trading will allow suppliers and producers to take account of the most up-to-date
information and, therefore, reduce risk of being out of balance.
The more trading in this market, the more likely it is to reflect the overall value of
staying in balance, thereby increasing confidence in the price. This in turn will
affect price formation in the day-ahead market and in forward markets.
-
Most Member States have organised intraday markets. In their Market Monitoring Report,
ACER points out a general trend to an increase in the volumes traded in national intraday
markets.
44
Ofgem,
https://www.ofgem.gov.uk/electricity/wholesale-market/liquidity
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Figure 1
–
ID traded volumes in selection of EU markets
–
2011-2014 (TWh).
Source: PXs and the CEER national indicators database (2015), as reported in "Market Monitoring Report
2014" (2015) ACER.
However, there remains significant scope for increasing liquidity. In the same report,
ACER analyse 13 markets that make up 95% of the liquidity in intraday markets, using as
a liquidity indicator the ratio of energy volumes traded to demand. The following shows
that only 5 markets had a ratio above 1%.
ES
12.1
%
IT
7.4
%
PT
7.6
%
DE
4.6
%
GB
4.4
%
SI
1.0
%
BE
1.0
%
SE
1.0
%
LT
1.0
%
FR
0.7
%
CZ
0.7
%
NL
0.2
%
PL
0.1
%
The organisation of national intraday markets is largely unregulated in EU law. A degree
of harmonisation has developed naturally, partially due to common actors in national
markets. However, significant differences still remain. In particular:
-
-
whilst most countries operate a continuous trading approach, some have intra-day
auctions;
gate closure times (i.e. when the market closes) vary from between 5 minutes (BE
and NL) to 120 minutes (HU) ahead of real time. In the Iberian market, which
operates auctions, the shortest gate closure time is just over two hours, and can
extend even further depending on the hour of delivery;
the granularity of products varies between 60 minute products and 15 minute
products;
the minimum size of bids varies between 0.1MWh to 1MWh;
the types of orders vary considerably;
demand response is not consistently allowed to participate;
whether bidding is at unit-level or portfolio-level;
whether the organised intraday-markets are exclusive (i.e. preventing bi-lateral
trading).
-
-
-
-
-
-
Currently, cross-border trading in the intraday timeframe is not harmonised, is generally
on a border-by-border basis and the total traded volumes are low: in 2014 only 4.1% of IC
capacity was used intraday, compared to 40% day-ahead.
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The CACM guideline
45
envisages a new, EU-wide cross-border market in the intraday
timeframe. Local markets will be indirectly impacted by its introduction, essentially
because it provides an extra choice for market participants on which platform to trade.
There are important interactions, notably because the two markets co-existing in this way
has the potential to split liquidity (i.e. split the trading across two markets as opposed to
one, thereby reducing the benefits of a highly liquid market). The more differences that
exist between local markets and between local markets and the cross-border market, the
greater the impact is likely to be as arbitrage opportunities between them will be reduced.
One issue exists in particular
–
that of gate closure times. The below diagram is an
illustration of the potential interactions between local and cross-border markets. While
both are open for trading, market participants can chose the best one, most likely driven
by price and/or products which match their needs, but potentially also by functionality and
ease-of-use of the trading platform. As such there should be a general trend towards
convergence of prices in these two markets as they will effectively be in direct competition
with each other. The more similarities in the specificities of the markets the more likely
this is to be the case. However, if the local market closes before the cross-border market,
the arbitrage opportunities are reduced as the market participants cannot freely trade
between the two. There is also a risk that local rules will mean that continued cross-border
trading will not be possible once the local market has shut, for example because it is on
this basis which the suppliers and producers provide 'firm' details on their contracted
energy to the TSO. The existence of different products and arrangements, and even
different IT systems on which to trade, also bears the risk of splitting liquidity between
different markets. However, whilst the longer-term objective should be to have one,
common market where all trading takes place and where liquidity is 'pooled', given the
starting point it is not necessarily beneficial to deliver this by harmonising all arrangements
in the short-term, as it could involve moving to the 'lowest common denominator,' as
described further below.
45
Commission Regulation (EU) 2015/1222 establishing a guideline on capacity allocation and congestion
management.
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Figure 2
–
Example co-existence of local and cross-border markets, where local
market closes before cross-border.
The design of some national markets may limit the ability for RES E or Demand Response
to participate, as they will prefer shorter products as this will help them accommodate more
variability in generation and demand. Also, if products do not at least reflect the imbalance
settlement period, then market participants will not have the ability to balance themselves
sufficiently frequently.
Finally, the closer to real time that market parties are allowed to trade, the more likely it is
that their supply and demand will be in balance when it comes to delivering and consuming
energy. This is especially relevant in a market sensitive to weather fluctuations where
changes can happen after the market has closed and the participants are not able to buy or
sell energy to make up for this. It therefore becomes the responsibility of the TSO as part
of the balancing market. However, the risk is that, if set too close, TSOs will not have the
time they need after being informed of the final market results to manage the system and,
in particular, deal with internal bottlenecks.
Deficiencies of the current legislation
As detailed above, there is very limited legislation in this area. The most significant piece
is the CACM Guideline, but this only indirectly addresses the operation of national markets
and, in most cases, will not directly lead to standardised trading within local markets,
which thereby potentially creates a barrier to cross-border trade and liquidity.
The Evaluation Report for market design concluded that
"the Third Energy Package does
not ensure sufficient incentives for private investments in the new generation capacities
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and network because of the minor attention in it to effective short-term markets and prices
which would reflect actual scarcity."
46
Presentation of the options
Option 0
–
Business as Usual
This option would leave local markets mostly unregulated, allowing for national
differences, but influenced by the arrangements for cross-border intraday and day-ahead
market coupling. The CACM Guideline requires the definition of a gate closure time on
each bidding zone border, which can be a maximum of 60 minutes. This could impact
decisions taken at national level, but this is not certain and differences are likely to remain.
Further, the definition of the products that can be taken into account in the cross-border
system are to be determined under the CACM Guideline which could, again, impact the
products which are provided in local markets.
Option 0+ Non-regulatory approach
There is very limited legislation in this area. Stronger enforcement of current rules
therefore does not provide scope to achieve a larger degree of harmoninsation of intraday
trading arrangements.
Voluntary cooperation has resulted in significant developments in the market and a lot of
benefits. However it may not provide for appropriate levels of harmonisation or certainty
to the market and legisaltion is needed in this area to address the issues in a consistent way.
Option 1
–
Fully harmonise all arrangements in local markets.
This option would see all arrangements harmonised, including gate opening times, gate
closing times, products to be offered, whether markets are exclusive, and mandatory
continuous trading rather than auctions. Gate closure time would be established as close to
real time as possible, to provide maximum opportunity for the market to balance its
positions before it became the TSO responsibility. Markets would be exclusive
–
i.e. no
bilateral trading
–
and power exchanges would be obliged to offer small products, in size
and duration
–
likely a minimum of 0.1MWh in 15 minute blocks. Demand response
would be able to participate in all markets.
Given the difference in technical characteristics of different markets (i.e. some have very
limited internal congestion so very short gate closure times are technically feasible, whilst
others need more time to take remedial actions), this option would likely see some markets
becoming larger (with gate closure times closer to real time) and some smaller (with gate
closure times having to move further away from real time, depending on the precise time
chosen). It would also mean that products would not necessarily reflect the difference in
national systems.
Given the technicalities of this option, it would likely be developed through implementing
legislation.
46
Section 7.3.2 of the Evaluation
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Option 2 - Selected harmonisation, with additional flexibility
This option would introduce standardisation of gate closure time and products in a more
flexible way, specifically allowing some flexibility in national markets to reflect their
differentiated nature. In particular, under this option, legislation would specify:
-
that intraday gate closure time in national markets must not be longer than the cross-
border intraday gate closure time. This would ensure that national markets are not
'taken out of the picture' before the cross-border markets close, and would, in effect,
mean that at a minimum market participants are allowed to trade as close as one hour
ahead of real time.
that power exchanges must offer products that reflect the imbalance settlement period.
This will ensure that market participants are able to trade at a frequency which allows
them to stay in balance.
that barriers to demand response participating in intraday markets must be minimised
–
specifically, minimum bid size should allow for participation and there should be no
administrative barriers put in place.
-
-
This option would also see more principles added to legislation, with the aim of progressive
harmonisation over time on those design features not touched.
Comparison of the options
Option 0 (Business as usual) would keep the
status quo
and leave intraday markets to
evolve within Member States, with no guarantees they would develop along the same lines,
except in some areas that existing legislation touches (for example, on minimum and
maximum bid prices). There would likely be an impact as a result of the implementation
of market coupling in the intraday time-frame. With significant differences, there is a risk
that liquidity is split and benefits of short-term markets to the integration of RES E and
demand response muted.
Option 1
–
full harmonisation
–
would likely see significant changes in a number of
markets. It would involve selecting a gate closure time and applying that to all national
markets. Whilst the precise timing could vary, it would mean that some countries would
need to keep their markets open longer, and some would need to close their markets earlier
than they currently do (notably in Belgium and the Netherlands, where trades can currently
take place up to 5 minutes prior to delivery)
–
harmonising gate closure times to that of the
shortest in Europe would likely be unachievable for many Member States, particularly
larger ones where the TSO requires more time between knowing the market results and
real time in order to solve internal congestion (the market is blind to congestion within a
bidding zone).
This option would also involve harmonising other aspects, as detailed above. Power
exchanges can be seen as the conduit for energy trades across borders so harmonising the
rules on which trading takes place will minimise differences between national markets and
with the common cross-border market. By increasing the arbitrage opportunities across
these markets, the risk of splitting liquidity is reduced.
On the surface, this might seem like an appropriate response akin to other single market
measures that harmonise standards so that they can be traded within the EU with minimal
barriers. However, in reality this is likely to be much more complex. A significant amount
of the process is IT-driven, and the arrangements have not yet been put in place
–
it would
therefore be very difficult to determine what the local arrangements should be. Further,
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there is a lack of evidence that such harmonisation would indeed lead to more cross-border
trade
–
the costs associated with changing IT could be significant with little benefit.
Given that the common cross-border market will likely be more complex (e.g. given the
number of variables, Member States, the fact that calculations will need to consider
available cross-border capacity) in the immediate future this market, and the IT
infrastructure that supports it, may not be able to accommodate the more granular market
arrangements that exist in some Member States. As such, moving all national markets to
the same design details of that of the cross-border market could entail some having to
reduce their granularity, move gate closure time further away from real-time, etc. This
would not fit with the objectives of the present proposal, which aims for increased
flexibility.
Option 2, however, would provide a much more proportionate response. Rather than
specifying a value for the gate closure time in local markets it would specify that it should
be no longer than the cross-border gate closure time. It will provide more opportunity for
arbitrage between markets. It will also move gate closure times closer to real-time in many
markets, which will provide more opportunities for RES E to balance themselves and
demand response to participate in the market, without forcing those markets which already
apply very short-term trading rules to switch to longer timeframes. With regards to
products the markets should be able to accommodate demand-response and small-scale
RES E. It will also leave the most technical characteristics to the implementation of the
CACM Guideline, which has the advantage of allowing specifics to be discussed in detail
with market parties and for more flexibility, i.e. allowing for easy adaptation if and when
requirements need to change.
Whilst this option will not eliminate the risk of splitting liquidity, there is in fact some
evidence that two markets can co-exist and increase overall traded volumes. In a study
looking at the impact of the introduction of an intraday auction for 15 minute products in
Germany
47
, it was found that, whilst the auction pulled some value away from the
continuous intraday market, the total traded volumes increased.
47
"Intraday
Markets for Power: Discretizing the Continuous Trading"
Karsten Neuhoff, Nolan Ritter,
Aymen Salah-Abou-El-Enien and Philippe Vassilopoulos (2016)
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Figure 3: Volumes on the 15mn intraday market and the share of quarters in total
trading volumes (quarters+hours), EPEX (DE)
Source: Neuhoff et al (2016)
The option will also provide a good starting point for progressively harmonising with the
longer-term aim of
one, common intraday market with local specificities minimised to
situations where they are justified due to local differences.
Specific impacts relating to changes in short-term markets are discussed in Section 6.1.3.
With regards to intraday, the results of the modelling indicate positive impacts of
harmonising intraday arrangements in Europe, specifically allowing for the further
reduction of RES E curtailment and lesser use of replacement reserves by 460 GWh and
95 GWh, respectively
Subsidiarity
Given that the EU energy system is highly integrated, prices in one country can have a
significant effect on prices in another, as can arrangements in local markets. Differences
in the operation of local markets can present a barrier to the cross-border trade of energy,
and continuing differences between local markets, and between local markets and the
single cross-border market, risks splitting liquidty and constraining the benefits of a
common cross-border market This will impact on liquidity and the amount of trading
which can take place, as well as erode the benefits of competition and a larger market place
in which energy can be bought and sold.
EU-level action is, therefore, necessary to ensure that the national markets are comparable,
that they enable maximum cross-border trading to happen, and facilitate liquidity as much
as possible. .
There is also a critical link with the CACM Guideline, which establishes principles and
required further methodologies for the operation of intraday markets in the cross-border
context, as well as a link with the upcoming Balancing Guideline. EU-level action is
required to ensure that trading in local markets can reap maximum benefits of the cross-
border solution under development.
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Stakeholders' opinions
Most stakeholders agree on the importance of liquid short-term markets, particularly
intraday and balancing, to the efficient operation of the internal electricity market. They
are, in general, seen as a critical part of ensuring that RES E can be propely intergrated,
notably allowing renewable generators to trade closer to real-term, as well as to stimulating
investment in sources of flexibility such as demand response. Most call for speedy
implementation of common cross-border intraday trading (market coupling) via the XBID
project, whilst recognising the progress that has already been made in day-ahead market
coupling.
Wind Europe calls upon the EU to "ensure
continuous intraday trading with harmonised
gate closure times closer to real time; complementary auctions may be introduced to
increase liquidity".
They argue that "implementing
well-functioning intraday markets
across borders with gate-closure close to real-time will 1) provide renewable producers
with opportunities to adjust their schedule in case of forecasts errors, 2) smooth out the
variability induced by renewable in-feed over broader geographical areas"
48
.
In their publication
"Electricity Market Design: fit for the low-carbon transmision",
Eurelectric state:
"The development of robust cross-border intraday and balancing markets will be crucial
to ensure that the system remains balanced as the share of renewables continues to grow.
It is therefore necessary to promote a liquid continuous implicit cross-border intraday
market with harmonised products in all member states, while capacity pricing shall not
drain liquidity nor reduce the speed of market processes. The market shall be enabled to
determine the most economic dispatch until a gate closure set as close to real-time as
possible (e.g. 15 minutes). TSOs shall only perform the residual balancing of the system."
49
SolarPower Europe state
"progress is needed in particular with a view to achieving better
liquidity and integration of intraday and balancing markets. These short-term markets are
crucial as variable renewable energy sources take a more important role in the power mix.
Products and services should be re-defined to improve the granularity of these markets
and enable the sale of different system services that solar power and other renewables, but
also storage and demand participation can provide."
50
ENTSO-E make the point that
"Accurate short-term market price formation is needed to
reveal the value of flexibility in general and of DSR specifically"
51
and ACER/CEER that
"it
is imperative that everything is done to make sure that price signals reflect scarcity and
to create shorter-term markets which will reward those who provide the flexibility services
which the system increasingly needs."
Further, they state that
"the intraday and balancing
markets will be increasingly important to valuing flexibility and there needs to be a push
48
49
50
51
"A market design fit for renewables".
Wind Europe submission of 27 June 2016
"Electricity Market Design: fit for the low-carbon transmision".
Eurelectirc 2016, available at
http://www.eurelectric.org/media/272634/electricity_market_design_fit_for_low-carbon_transition-
2016-2200-0004-01-e.pdf
"Creating a competitive market beyond subsidies"
July 2015,
Market Design of Demand Side Response"
Policy Paper, November 2015
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to deliver the cross-border intraday (XBID) project and to implement the Network Code
on Electricity Balancing as soon as possible."
52
The March 2016 Electricity Regulatory Forum (the "Florence Forum"), a forum for
stakeholders to engage on wholesale market regulatory issues, made the following relevant
conclusion:
"The Forum acknowledges that, whilst cross-border day-ahead and intraday markets will
see significant harmonisation as part of the implementation of the Capacity Allocation and
Congestion Management guideline, there is significant scope for ensuring that national
markets are appropriately designed to accommodate increasing proportions of variable
generation. In particular, the Forum invites the Commission to identify those aspects of
national intraday markets that would benefit from consistency across the EU, for example
on within-zone gate closure time and products that should be offered to the market. It also
requests for action to increase transparency in the calculation of cross-zonal capacity,
with a view to maximising use of existing capacity and avoiding undue limitation and
curtailment of cross-border capacity for the purposes of solving internal congestions."
52
Joint ACER-CEER
response to European Commission’s Consultation on a new Energy Market Design,
October 2015
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2.3. Improving the coordination of Transmission System Operation
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Summary table
Objective: Stronger coordination of Transmission System Operation at a regional level
Option 0
BAU
Limit the TSO coordination efforts to the
implementation of the new Guideline on
Transmission System Operation (voted at the
Electricity Cross Border Committee in May
2016 and to be adopted by end-2016) which
mandates the creation of Regional Security
Coordinators (RSCs) covering the whole
Europe to perform five relevant tasks at regional
level as a service provider to national TSOs.
Lowest political resistance.
Option 1
Enhance the current set up of existing RSC by
creating Regional Operational Centers (ROCs),
centralising some additional functions at regional
level over relevant geographical areas and
delineating competences between ROCs and
national TSOs.
Option 2
Go beyond the establishment of ROCs
that coexist with national TSOs and
consider the creation of Regional
Independent System Operators that can
fully take over system operation at
regional level. Transmission ownership
would remain in the hands of national
TSOs.
Option 3
Create
a
European-wide
Independent System Operator
that can take over system
operation at EU-wide level.
Transmission ownership would
remain in the hands of national
TSOs.
Description
Suboptimal in the medium and long-term.
Most suitable: Most suitable option(s): Option 1
(Option 2 and Option 3 constitute the long-term vision)
Cons
Enlarged scope of functions assuming those tasks
where centralization at regional level could bring
benefits
A limited number (5 max) of well-defined regions,
covering the whole EU, based on the grid topology
that can play an effective coordination role. One
ROC will perform all functions for a given region.
Enhanced cooperative decsion-making with a
possibility to entrust ROCs with decision making
competences on a number of issues.
Could find political resistance towards
regionalisation. If key elements/geography are not
clearly enshrined in legislation, it might lead to a
suboptimal outcome closer to Option 0.
Pros
Improved system and market operation
leading to optimal results including
optimized infrastructure development,
market facilitation and use of existing
infrastructure, secure real time operation.
Seamless and efficient system
and market operation.
Politically challenging. While this option
would ultimately lead to an enhanced
system operation and might not be
discarded in the future, it is not
considered proportionate at this stage to
move directly to this option.
Extremely
challenging
politically. The implications of
such an option would need to be
carefully
assessed.
It
is
questionable whether, at least at
this stage, it would be
proportionate to take this step.
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Detailed description of the baseline
Operation of the transmission system
Traditionally, prior to the restructuring of the energy sector, most electricity utilities were
run by national and very often state-owned monopolies. These were in most cases
vertically integrated utilities that owned and operated all the generation and system assets
in their allocated territories.
The adoption and implementation of the three energy packages have led to the introduction
of competition in the generation and supply of electricity, the introduction of wholesale
electricity markets for the trading of electricity as well as to different degrees of unbundling
of transmission and distribution activities, which constitute monopoly activities.
Figure 1. The electricity value chain
generation
Erzeugung
trading
Handel
transmission
Übertragung
distribution
Verteilung
Vertrieb
supply
competitive activity
competitive activity
Source: European Commission
regulierter Bereich
monopoly activity
The fact that the activity of electricity transmission system operation is mostly national in
scope derives from the past existence of vertically integrated utilities that were active
throughout the whole electricity supply value chain. Following the restructuring of the
electricity sector, Member States naturally tasked TSOs with the responsibility of ensuring
the secure operation of the electricity system at national level.
This approach is currently reflected in the EU legislation. Article 12 of the Electricity
Directive establishes that each TSO shall be responsible,
inter alia,
for managing the
electricity flows on the system, taking into account exchanges with other interconnected
systems. The Commission Implementing Regulation establishing a guideline on electricity
transmission system operation ('System Operation Guideline') specifies further this
obligation and sets out a requirement on TSOs to ensure that their transmission system
remains in the normal state and makes them responsible for managing violations of
operational security
53
.
Coordination of transmission system operation: shift from a voluntary approach to a
mandatory framework
Driven by the lessons learnt from the serious electrical power disruption in Europe in 2006,
European TSOs have pursued enhancing further regional cooperation and coordination. To
this end, TSOs voluntarily launched Regional Security Coordination Initiatives (RSCIs),
53
The System Operation Guideline was voted on 4 May 2016 and is due to be adopted after scrutiny by
the Council and the European Parliament.
https://ec.europa.eu/energy/sites/ener/files/documents/SystemOperationGuideline%20final%28provisi
onal%2904052016.pdf
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entities covering a greater part of the European interconnected networks aiming at
improving TSO cooperation. The main RSCIs in Europe are Coreso and TSC, both
launched in 2008, followed by the ongoing development and establishment of additional
RSCIs, such as SCC in Belgrade (launched in 2015) and an RSCI to be launched by Nordic
TSOs by the end of 2017. Currently, RSCIs monitor the operational security of the
transmission system in the region where the TSOs with membership in the RSCIs are
established and assist TSOs proactively in ensuring security of supply at a regional level.
By performing these functions, RSCIs provide TSOs with detailed forecasts of security
analysis and may propose coordinated measures that TSOs may decide or not to
implement.
In December 2015, all European TSOs except for SEPS a.s., the Slovakian TSO, signed a
multi-lateral agreement to roll out RSCIs in Europe and to have them deliver core services
to support the TSOs carry out their functions and responsibilities at national level.
R&D results:
Tools for TSOs to deal with an increase in cross-border flows and variability
of generation are being developed in European projects like ITESLA and UMBRELLA.
They show that coordinated operational planning of power transmission systems is
necessary to cope with increased uncertainties and variability of (cross-border) electricity
flows. These tools help decrease redispatching costs and the available cross-border
capacity and flexibility while ensuring a high level of operational security.
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Figure 2 State of play of the voluntary membership of TSOs in RSCIs across the
European Union.
Source: European Commission (June 2016)
The voluntary establishment of RSCIs has been widely recognised as a positive step
forward for the enhancement of cooperation of transmission system operation and has been
recently formalised in EU legislation with the new System Operation Guideline.
Building on the emerging regional initiatives, the System Operation Guideline takes a
further step and mandates the cooperation of EU TSOs at regional level through the
establishment of maximum six regional security coordinators (RSCs) which will cover the
whole EU to perform a number of relevant tasks at regional level as service providers to
national TSOs.
The tasks that RSCs will perform pursuant to the System Operation Guideline are: (i)
regional operational security coordination; (ii) building of the common grid model; (iii)
regional outage coordination; and (iv) regional adequacy assessment. The task of capacity
calculation follows from the implementation of the CACM Guideline and is not assigned
in the System Operation Guideline. The draft Commission Regulation establishing a
network code on Emergency and Restoration intends to extend the tasks of RSCs to include
a consistency assessment of the TSOs' system defence plans and restoration plans.
The framework set out in the System Operation Guideline is meant to build on the existing
voluntary initiatives of TSOs (Coreso and TSC). It requires each TSO to join a RSC and
allows a degree of flexibility to TSOs to organise the coordination of regional system
operation. In this regard, the TSOs of the different capacity calculation regions will have
the freedom to appoint more than one RSC for that region and to allocate the tasks, as they
deem most efficient, between them.
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Based on the deadlines for implementation envisaged in the System Operation Guideline,
RSCs should be fully operational around mid-2019.
Box 1: Support functions to be carried out by RSCs under the network codes and
guidelines
Common grid model:
The common grid model provides an EU-wide forecasted view of all major grid assets
(generation, consumption, transmission) updated every hour. RSCs will participate in the iterative process
starting from the collection of individual grid models prepared and shared by TSOs and aiming at delivering
to all RSCs and TSOs, a common grid model adequate for the other functions listed below. This function is
required at least for timeframes from year-ahead to intraday (year-ahead, week-ahead, day-ahead, and
intraday).
Operational planning security analysis:
RSCs will identify risks of operational security in any part of their
regional area (mainly triggered by cross-border interdependencies). They will also identify the most efficient
remedial actions (i.e., actions implemented by TSOs aimed at maintaining or returning the electricity system
to the normal system state) in these areas and recommend them to the concerned TSOs, without being
constraint by national borders. This function covers at least the day-ahead and intraday timeframes.
Coordinated capacity calculation:
RSCs will calculate the available electricity transfer capacity across
borders, using flow-based (FB) or net transfer capacity (NTC) methodologies. These methodologies aim at
optimising cross-border capacities while ensuring security of supply. This function is carried out at least on
the D-2 (for day-ahead capacity allocation) and D-1/ intraday (for intraday capacity allocation) timeframes.
Short and very short-term adequacy forecasts:
RSCs will provide TSOs with consumption, production
and grid status forecasts from the day-ahead up to the week-ahead timeframe. In particular, RSCs will
perform a regional check/update of short/medium term active power adequacy, in line with agreed ENTSO-
E methodologies, for timeframes shorter than seasonal outlooks. This function is carried out week-ahead
(until day-ahead only if scarcity is detected or if there are changes in relevant hypotheses compared to week-
ahead).
Outage planning coordination:
This function consists in creating a single register for all planned outages
of grid assets (overhead lines, generators, etc.). RSCs will identify outage incompatibilities between relevant
assets whose availability status has cross-border impact and limit the pan-European consequences of
necessary outages in grid and electricity production by coordinating planning outages. RSCs will carry out
this function in the year-ahead timeframe with updates up to week-ahead (on TSO requests).
Consistency assessment of the TSOs' system defence plans and restoration plans:
RSCs will assist TSOs
in ensuring the consistency of the system defence plans and restoration plan.
Deficiencies of the current legislation
The regional TSO cooperation model resulting from the adoption of electricity network
codes and guidelines constitutes a positive development compared to the existing voluntary
cooperation. However, as explained below, this step, while being effective in the short-
term, is not sufficient in the medium and long-term.
The unprecedented changes concerning the integration of the European electricity markets
and the European agenda for a strong decarbonisation of the energy sector, resulting in
increasingly higher shares of decentralized and often intermittent renewable energy
sources, have made the operation of the national electricity systems much more interrelated
than in the past.
The recently voted System Operation Guideline has not entered into force and been
implemented yet. Nonetheless, as highlighted in pp 32-33 of the Evaluation, the challenges
the EU power system will be facing in the medium to long-term are pan-European and
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cannot be addressed and optimally managed by individual TSOs, rendering the current
legal framework concerning system operation not adapted to the reality of the dynamic and
intermittent nature of the future electricity system and putting into question whether the
mandated cooperation of TSOs via RSCs is fit for purpose in the post 2020 context.
First, the functions envisaged for RSCs in the System Operation and in the CACM
Guideline will not suffice in the medium to long-term as there is an increasing need for
electricity systems to be operated on a regional basis. Furthermore, there is room to enlarge
the scope of functions that would increase the efficiency of the overall system, if performed
at regional level.
Second, the geographical scope of RSCs set out in the System Operation Guideline could
not be efficient in the post 2020 context. RSCIs have grown organically with political
considerations in mind, rather than following criteria solely based on the technical
operation of the grid. The degree of flexibility envisaged in the System Operation
Guideline will allow TSOs to maintain that
status quo,
undermining the goal of having a
regional entity that oversees system and market operation in the region.
Figure 2
representing the current membership of TSOs in RSCIs across the Union reflects this
situation (e.g., membership of TenneT NL, the TSO of the Netherlands, in TSC as opposed
to Coreso). The coordination with other regional groupings of TSOs deriving from the
implementation of other network codes and guidelines is also an issue. For example, given
the degree to which the grid is meshed in the CWE and CEE regions, it is virtually
impossible to draw permanent lines dividing the regions and still respect the electrical
interdependencies. Hence, the presence of two RSCIs (Coreso and TSC) for this region
does not seem the optimal solution to play an effective coordination role.
Third, the implementation of the System Operation Guideline will entail that RSCs will
play an increasingly important support role for TSOs. However, the full decision-making
responsibility will remain with TSOs who will have to do the grid planning while taking
into consideration also new options to grid extensions (such as energy storage). RSCs will
not have executive powers and their activities will be limited to providing planning
services to individual TSOs, who can accept or reject those services and who will retail
full control of and accountability for the planning and operation of their individual
networks. For example, when deciding about the commercial cross-border capacities in a
given region which are already calculated at regional level, the decision taken by RSCs are
non-binding meaning that they can be considered as an input that can be changed by TSOs
based on national interest (e.g. in case of scarcity of supply in one country the TSO might
be tempted to reduce their export capacities but this might not be the best decision from a
regional system security perspective) or due to constraints in the national legal framework.
In this regard, the rejection of a recommendation by a TSO would suffice to put in question
the overall set of recommendations issued by a RSC. For example, if in a recommendation
for an optimal set of remedial actions a given TSO did not agree, this would imply the
whole recalculation of remedial actions for the region since such measures are usually
interdependent. There is additional evidence pointing out to this problem. The ACER
market monitoring report 2015 (to be published in 2016) remarks that there are strong
indications that during the capacity calculation process TSOs resort to unequally treating
internal and cross-zonal flows on their networks.
To conclude, while the enhanced regional TSO cooperation resulting from the adoption of
electricity network codes and guidelines constitutes a positive step forward, it is important
to note that it will not allow realising the full potential of these regional entities in the
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medium to long-term. If the benefits of market integration are to be fully realised, TSOs
will have to cooperate even more closely at regional level. This will require adjusting the
way in which the operation of the electricity system will be managed under the System
Operation Guideline.
Presentation of the options
Option 0 - BAU
Option 0 would be to stop the coordination efforts at this stage and limit it to the progress
achieved with the implementation of the System Operation Guideline.
The upcoming RSCs will have the following features:
i.
Functions. Five main functions
54
will be performed by the upcoming RSCs as
service providers to national TSOs under the network codes and guidelines (see
Box 1
above for a more detailed explanation of each of these functions).
a. Coordinated Security Analysis (including Remedial Actions-related
analysis)
b. Common Grid Model Delivery
c. Outage Planning Coordination
d. Short and Very Short Term Resource Adequacy Forecasts
e. Coordinated Capacity Calculation
The addition of new functions would mainly depend on the voluntary initiative of
TSOs, which in some instances could lead to inefficient outcomes given that they
would not always have the "regional" perspective in mind but rather their own
interest, particularly given the flexibility at the time of defining the geographical
scope.
Geographic scope. While RSCs will give full coverage across the EU, the size and
composition of the regions where they will be established may not always be
defined having the technical operation of the grid in mind. Business and political
criteria could also play a role. In particular, TSOs in a region would continue having
flexibility to decide which RSC provides a given service (including new ones
developed voluntarily) to that region. This would allow a given region to get
services from different RSCs. While this has been accepted as a valid compromise
in the short-term, it undermines the goal of having a regional entity with enhanced
overview over system and market operation in the region.
ii.
Decision-making responsibilities. The upcoming RSCs will not have any decision-
making powers but a purely advisory role. The responsibility for system operation
will remain with TSOs at national level. The fact that RSCs issue recommendations
means that ultimately an individual TSO may be constrained by the national
framework and reject the implementation of such recommendation, against the
interest of all the other TSOs of the region. Hence, the set up of the RSC being able
54
Six functions with the adoption of the Emergency and Restoration network code
('Consistency
assessment of TSOs' system defence plans and restoration plans').
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to provide an added value at regional level would be compromised. For example,
as described above, if in a recommendation for an optimal set of remedial actions
a given TSO did not agree, this would imply the whole recalculation of remedial
actions for the region since these measures are usually interdependent.
iii.
Institutional layout/governance. The interaction between the RSCs, NRAs, TSOs,
ACER and ENTSO-E would remain as set out in the System Operation Guideline.
Essentially, TSOs and NRAs would continue to be responsible for the direct
implementation and oversight of RSCs at national level. ACER and ENTSO-E
would remain responsible for ensuring the cooperation of NRAs and TSOs at EU
level, respectively.
Option 0+: Non-regulatory approach
Stronger enforcement would not suffice to address the needs of the electricity system
regarding stronger TSO cooperation at regional level.. As in option 0, any progress beyond
the framework in the System Operation Guideline and the application of other network
codes would depend on the voluntary initiatives of TSOs. However, the voluntary
initiatives would be limited due to the constraints resulting from differing legislation at
national level. Hence, stronger enforcement or a voluntary approach is not a possible
option.
Option 1: Enhance the current set up of existing RSCs by creating ROCs, centralising some
additional functions over relevant geographical areas and optimising competences between
ROCs and national TSOs
Option 1 would aim at enhancing the current set up of existing RSCs by creating ROCs.
ROCs are not meant to substitute TSOs but to complement their role at regional level. This
option would set out a number of basic elements in legislation but allow flexibility to
TSOs to work out the details on how the ROCs will function and perform their tasks. ROCs
will present the the following features:
i.
Functions. Enlarged scope of functions, assuming new tasks where centralization
at regional level could bring benefits. These functions would not cover real time
operation which would be left solely in the hands of national TSOs. In addition to
the functions emanating from existing network codes and guidelines (see
Box 1),
these functions would be:
a. Solidarity in crisis situations: Management of generation shortages;
Supporting the coordination and optimisation of regional restoration
b. Sizing and procurement of balancing reserves
c. Transparency: Post-operation and post-disturbances analysis and reporting;
Optimisation of TSO-TSO compensation mechanisms
d. Risk-preparedness plans (if delegated by ENTSO-E)
e. Training and certification (if delegated by ENTSO-E)
ii.
Geographic scope. A limited number of well-defined regions, covering the whole
EU. TSOs establishing the ROCs will need to decide the scope of these regions
based on technical criteria (e.g. grid topology) to ensure that they can play an
effective coordination role. In contrast to what is currently in the System Operation
Guideline, each ROC would perform all functions for a given region. Larger
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regions could include, if necessary, back-up centres and/or sub regional desks when
for example some functions would require specific knowledge of smaller portions
of the grid.
iii.
Cooperative decision-making. ROCs would have an enhanced advisory role for all
functions. In order to respect to the maximum possible extent the regional
recommendations, TSOs should transparently explain when and why they reject
the recommendation of the ROC. Given that a role limited to issuing
recommendations may lead to sub-optimal results as regards the performance of
some of the functions
55
, decision-making powers could be entrusted to ROCs for
a number of relevant issues (i.e., remedial actions, capacity calculation) either
directly by a Regulation or subsquentely by mutual agreement of the NRAs or
Member States overseeing a certain ROC. By optimising decision-making
responsibilities between ROCs and national TSOs the seamless system operation
between the ROCs and the TSOs would be ensured.
Institutional layout/governance. Enhanced cooperation between TSOs would be
accompanied by an increased level of cooperation between regulators and
governments as well as by an increased oversight from ACER and ENTSO-E.
iv.
55
This sub-optimal situation would derive from the fact that the rejection by a single TSO of the
recommendation issued by the ROC would put in question the overall set of recommendations.
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Box 2: Additional functions performed by ROCs under Option 1
-
Solidarity in crisis situations:
-
Management of generation shortages.
ROCs would optimise the generation park in a region while
attempting
to increase transmission capacity to the Member State which suffers generation
shortage. The aim of this function is to avoid load cuts (energy non served situations) in a country
while other countries still optimise the market and/or enjoy high generation margins.
-
Supporting the coordination and optimisation of regional restoration.
ROCs would recommend the
regional necessities during restoration (e.g., resynchronisation sequence of large islands in case of
the split of a synchronous area).
Sizing and procurement of balancing reserves:
-
Regional calculation of daily balancing reserves.
ROCs would carry out regional sizing of daily
balancing reserves (disregarding political borders and considering only technical limitations related
to geographical dispersion of reserves) on the basis of common probabilistic methodologies (i.e.
balancing reserve needs based on different variables such as RES generation forecast, load
fluctuations and outage statistics).
-
Regional procurement of balancing reserves.
ROCs would create regional platforms for the
procurement of balancing reserves, complementing the regional sizing of balancing reserves.
Transparency:
-
Post operation and post disturbances analyses and reporting.
ROCs would carry out centralised
post-operations analyses and reporting, going beyond the existing ENTSO-E Incidents
Classification Scale (ICS).
-
Optimisation of TSO-TSO compensation mechanisms.
ROCs would administer common money
flows among TSOs, such as Inter-TSO Compensation (ITC), congestion rent sharing, re-dispatching
cost sharing, cross-border cost allocation (CBCA). Furthermore, ROCs should propose
improvements to the schemes based on technical criteria and aiming for the optimal overall
incentives.
Risk-preparedness plans.
If delegated by ENTSO-E, the ROCs' function would be to identify the
relevant risk scenarios in its region that the risk preparedness plans should cover. Based on ROCs'
proposals, Member States would develop the plans. ROCs could organise crisis simulations (stress
tests) together with Member States and other relevant stakeholders. During such crisis simulations the
plans would be tested to check if they are suited to address the identified cross-border or regional crisis
scenarios.
Medium term adequacy assessments:
if delegated by ENTSO-E, ROCs would complement the
ENTSO-E seasonal outlooks with adequacy assessments carried out in a regional context where
possible crisis scenarios (e.g. prolonged cold spell), including simultaneous crisis, should be identified
and simulated.
Training and certification.
The network code on staff training and certification as foreseen in the
ACER framework guideline on system operation is still pending. ROCs could cover functions related
to trainings between TSOs as well as centralise of some trainings in issues related to cross-border
system operation. Further, this function should allow regional training on simulators (IT system based
on a relevant representation of the system, including networks, generation and load).
-
-
-
-
-
Option 2: Creation of Regional Independent System Operators
Option 2 would be to go beyond the establishment of ROCs that coexist with national
TSOs and consider the creation of Regional Independent System Operators (RISOs) that
can fully take over system operation at regional level.
RISOs would have the following features:
i.
Functions. RISOs would have an enlarged scope of functions compared to ROCs.
In addition to the functions under Option 1, RISOs would also be responsible for
real time operation of the electricity system (e.g., operation of real time balancing
markets) and for infrastructure planning. Infrastructure related functions could
include for example the identification of the transmission capacity needs:
proposing priorities for network investments based on the long-term resource
adequacy assessment, the situation in the interconnected system and identified
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structural congestions, while considering an interconnected system without
political borders.
ii.
iii.
Geographic scope. The scope of RISOs would be the same as for ROCs.
Decision-making responsibilities. All system operation functions would be
performed by the RISOs, which would have decision-making powers. Existing
TSOs would remain as transmission owners and solely operate physically the
transmission assets and provide technical support to RISOs (e.g., collection and
sharing of data).
Institutional layout/Governance. Additional changes in the institutional framework
would be required to enable the RISO approach. For example, it would be
necessary to amend the powers and competences of TSOs, of regulatory authorities
and of ACER in order to ensure the appropriate oversight of these entities. It would
also be necessary to consider aspects such as the financing of RISOs or the
applicability of unbundling rules.
iv.
Option 3: creation of a European-wide Independent System Operator
Option 3 would imply the creation of a European-wide Independent System Operation (EU
ISO) that would take over system operation at EU-wide level.
This entity would have the following features:
i.
ii.
iii.
Functions. The functions would be the same as those proposed under Option 2 for
RISOs.
Geographic scope. The EU ISO would be responsible for system operation at EU-
wide level.
Decision-making responsibilities: The EU ISO would perform all system operation
functions and hence would have decision-making powers. TSOs would solely
operate physically the transmission assets and provide technical support to RISOs
(e.g., collection and sharing of data).
Institutional layout/Governance: significant changes would be required in the
institutional framework to enable the creation of an EU ISO and an effective
oversight of its acitivities. It would be necessary to amend the powers and
competences of TSOs, of regulatory authorities and of ACER. It would also be
necessary to consider aspects such as its financing, monitoring of its performance,
etc.
iv.
Comparison of the options
The following Section provides a comparison of the options described above based on the
four main elements identified: (i) functions; (ii) geographical scope; (iii) decision-making
competences; and (iv) institutional layout/ governance. Given that only a few studies have
been carried out on this field, the assessment of the options will be mainly qualitative,
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based on the feedback received from stakeholders and on the content of the studies
published to date, and providing figures where they exist.
(i)
Functions
It is not possible to provide a complete quantification of the costs and benefits of each of
the Options as regards the set of functions to be performed at regional or EU level given
that few studies have assessed these costs and benefits. However, the insights from several
previous studies cover the potential benefits of a supranational approach to system
operation.
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Table 1 Functions that would be covered under each of the options
RSCs
(Option
0)
ROCs
(Option
1)
RISOs/EU
ISO
(Options 2
and 3)
System Operation
Coordinated Security Analysis (including Remedial Actions-
related analysis)
Common Grid Model Delivery
Outage Planning Coordination
Short and Medium Term Resource Adequacy Forecasts
Regional system defence and restoration plans
Centralised post operation analyses and reporting
Training and certification
Market Related
Coordinated Capacity Calculation
Coordinated sizing and procurement of balancing reserves
Network Planning
Identification of the transmission capacity needs
Technical and economic assessment of CBCA cases
Administration of TSO-TSO compensation mechanisms (ITC,
congestion rent sharing, redispatching cost sharing, CBCA)
Risk-preparedness
Support Member States on development of risk preparedness
plans
Source: DG ENER
x
x
x
x
x
x
56
x
x
x
x
x
x
x
58
x
x
x
x
x
x
x
x
x
x
x
57
x
x
x
x
x
x
56
57
58
It could include decision-making powers.
The CACM Guideline provides for regional capacity calculators. However, following the commitments
of ENTSO-E, this role could be already assumed for RSCs.
It could include decision-making powers.
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Table 2 Qualitative estimate of the economic impact of the Options:
Option 0:
RSC
approach
Option 1:
ROC
approach
Option 2:
RISO
approach
Option 3:
EU
ISO approach
Economic Impact
Enhancing security of supply by
minimising the risk of blackouts
59
60
0/+
+
++
++
Lowering costs through increased
efficiency in system operation
61 62
63
0/+
++
+++
+++
Maximising transmission capacity
offered to the market
64
Reducing the need of remedial
actions by coordinating and
activating in a coordinated way
redispatching
65 66
Minimising the costs of balancing
provision by taking a more
coordinated approach towards the
sizing of balancing reserves
67 68 69
Optimisation
planning
70
of
infrastructure
0/+
++
+++
+++
0/+
++
+++
+++
0/+
++
+++
+++
0
0
++
+++
Enhancing transparency
71
0
0/+
+
+
Costs of implementation72
0/-
-
---
----
Other impacts
Administrative
governance
impacts/
0/-
-
--
---
Source: DG ENER.The assumptions in this table are based on the studies existing in this field as well as on
the feedback received from stakeholders in their response to the public consultation and from estimations
concerning the resources of RSCs and ENTSO-E.
In sum, as illustrated in Table 2, the set of functions in
Option 0
will entail limited costs
and benefits, since many of these functions are already carried out by RSCIs in their
supporting role to TSOs. The implementation of the System Operation Guideline and
establishment of ROCs will not involve significant changes to the
status quo.
The set of
additional functions under
Option 1
will entail efficiency gains and increase social welfare
that will derive from providing additional functions to ROCs to be optimised at regional
level (as opposed to national level)
73
. In addition, it will entail costs related to the shift of
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59
60
61
62
63
64
65
66
67
68
69
The financial and social impact of wide area security breaches is enormous: as estimated by ENTSO-E,
the economic impact of wide area security breaches could be really important; the cost of a 20 GW load
disconnection during a large brownout is estimated to 800 million euros per hour (i. e. 40 euros / kWh).
Blackouts have an even higher impact. This provides quantified insight into the importance of optimised
emergency and restoration efforts with a central coordination of locally required efforts.
ENTSO-E (2014), "Policy
Paper on Future TSO Coordination for Europe",
Retrieved from:
https://www.entsoe.eu/Documents/Publications/Position%20papers%20and%20reports/141119_ENTS
O-E_Policy_Paper_Future_TSO_Coordination_for_Europe.pdf
The management of generation shortages should increase the regional social welfare as a result of a
decrease of financial losses that would otherwise result from disconnection of load. It would also
increase solidarity and promote trust in the internal energy market.
Also, some of the benefits will derive from the optimisation of training and certification. TSOs will gain
more practical experiences using same tools, practicing common scenarios and sharing best practices.
This should lead to faster system restoration and more efficient tackling of regional-wide system events.
A regional approach to adequacy assessment enhances the use of cross-border connections at critical
moments, resulting in an overall less required generating capacity in Europe. The enhancement is
expected to increase with increasing variable renewable energy in the system. The IEA mentions a
benefit of 1.4 euros/MWh based on the study of Booz & co. An example for regional adequacy
assessment is provided by the Pentalateral Energy Forum.
A supranational approach (moving local responsibilities to ROCs) to capacity calculation can bring
significant welfare benefits due to more efficient use of infrastructure and the consequent benefits
coming from the improved arbitrage between price zones. The CACM Guideline Impact assessment
estimates the welfare gains of a supranational approach to flow-based capacity calculation to be in the
region of 200-600 million euros per year. These benefits would only partially materialise (20% of
welfare gains would not be realised) on a voluntary basis, leaving significant parts of the capacities used
in a suboptimal manner.
Significant benefits are expected by the fact that enhanced TSO cooperation minimises the need for
redispatching, especially costly emergency actions. To illustrate, Kunz et al. quantified the benefits of
coordinating congestion management in Germany: in case each TSO is responsible to relief overflows
within its own zone with its own resources, which reflects the current situation in Germany closest,
redispatch costs of 138.2 million euros per year accrue. Coordinating the use of transmission capacities
renders costs of 56.4 million euros per year. As a benchmark, one single unrestricted TSO across all
zones would have to bear redispatch expenditures of 8.7 million euros per year. Kunz et al. also
quantified the benefits of coordinating congestion management cross-border (for the region comprising
Germany, Poland, Czech Republic, Austria, Slovakia): without coordination, total costs of congestion
management amount to 350 million euros per year, they decrease to 70 million euros per year for
optimised congestion management (including remedial actions and flow-based cross-border capacity
allocation).
Kunz et al.,
"Coordinating Cross-Country Congestion Management",
DIW Berlin , 2016 and Kunz et
al.,
"Benefits of Coordinating Congestion Management in Germany",
DIW Berlin, 2013
As regards the regional sizing and procurement of balancing reserves, the added value of this function
is gain in social welfare due to decreased size of needed balancing reserves and gains in techno-economic
optimisation of the procurement of the needed balancing reserves. Shared balancing has cost advantages
residing from netting of imbalances between balancing areas and from shared procurement of balancing
resources or reserves. This can be based on exchanging surpluses or based on a shared or common merit
order for all balancing resources. Mott Macdonald mentions potential overall benefits from allowing
cross-border trading of balancing energy and the exchanging and sharing of balancing reserve services
of the order of 3 billion euros per year and reduced (up to 40% less) requirements for reserve capacity.
This is for a European electricity supply system with roughly 45% renewable energy.
Mott MacDonald (2013), "Impact
Assessment on European Electricity Balancing Market"
Retrieved
from:
https://ec.europa.eu/energy/sites/ener/files/documents/20130610_eu_balancing_master.pdf
According to the study carried out by Artelys on Electricity balancing: market integration & regional
procurement, regional sizing and procurement of reserves by ROCs could lead to benefits of 2.9 billion
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these functions from national to regional level (e.g., development of processes and tools at
regional level) and will have an impact on the institutional structures (i.e., need to adapt
the institutional framework to ensure the proper monitoring of implementation of the
functions).
Option 2
will present additional gains and costs compared to Option 1. The
benefits will result from the more integrated operation of the system at regional level as
well as from the additional set of functions to be performed by RISOs, which will comprise
real-time operation of the electricity system. The costs will derive from the need to develop
new methodologies, processes and tools to ensure the performance of these additional
functions and the need to adapt the current oversight of the performance of these functions.
Option 3
is the option that will entail most economic gains (deriving from the efficiencies
of performance of the functions at EU level) and also most implementation costs.
(ii)
Geographic scope
In the current context of the rolling out of RSCs (Option
0),
there will be certain flexibility
for TSOs to decide which coordinator provides a given service to a region. This could
allow a given region to get services from different providers. While this is an acceptable
compromise in the short and medium term, it partly undermines the goal of having a
regional entity with enhanced overview over system operation and market operation in the
region. In addition, although there will be full European coverage by the RSCs (with a
maximum number of 6), the size and composition of the regions is not always defined
having the technical operation of the grid in mind. Business and political criteria play also
a role in it.
70
71
72
73
Euros (compared to 1.8 billion euros benefits from national sizing and procurement). An EU-wide sizing
and procurement of balancing reserves would lead to benefits of 3.8 billion Euros.
The added value as regards the identification of the transmission capacity needs at regional level is the
provision of neutral, regional view of investments needs. The industry represented by Eurelectric claims
that "Network
investment planning and the coordination of TSOs' network investment decisions by the
RISOs are the next natural steps."
As regards the technical and economic assessment of cross-border
cost allocation (CBCA) cases, benefits are expected from higher efficiency and quicker processes for
important transmission infrastructure projects.
As regards the optimisation of TSO-TSO compensation mechanisms, the added value is increased
transparency and step-by-step optimisation of the schemes, resulting in more cost-efficient operation of
the system. This is supported by Eurelectric which states that
"Regarding coordination of network
investment decisions, this would require the development of mechanisms for inter-TSO money flows.
Development of inter-TSO money flows will also allow efficient coordinated redispatching, as requested
by the CACM Guideline. This is considered to be a key element for enabling efficient intraday capacity
(re-)calculation".
See Eurelectric, "Develop
a regional approach to system operation",
June 2016. As
regards, post operation and post disturbances analyses and reporting, the added value is increased
transparency, better regional understanding and improvement process, as well as and potential efficiency
gains.
The costs of establishing ROCs, RISOs or an EU ISO are estimated to range between 9.9 and 35.6
million EUR per entity. See "Electricity
Balancing"
Artelys (2016). The study does not provide a break
out of the costs between Options 1, 2 and 3 but assumes that the costs will vary depending on the
functions and responsibilities attributed to these entities.
For instance, the management of generation shortages based on seasonal outlooks should increase the
regional social welfare as a result of a decrease of financial losses that would otherwise result from
disconnection of load.
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Option 1
would allow ROCs to play an effective coordination role leading to enhanced
system security and market efficiency
–
given that the ROCs would be able to optimise the
operations over larger regions
74
. In contrast with Option 0, the regions would be defined
according to market and system operation criteria (e.g. grid topology). Having a limited
number of ROCs will also bring in savings in developing system operation tools. However,
there would be costs related to the need to adapt further the geographical scope from RSCs
to ROCs but this could be mitigated through a carefully planned implementation. In Option
1, ROCs would have the possibility to include back-up centres that ensure that one centre
can take over from the other if a problem arises and/or include sub-regional desks for
looking at issues where a more detailed assessment is needed. This could for example be
the case if a ROC is created for the Continental Europe synchronous area (or at least for
Central Western Europe and Central Eastern Europe) as a natural evolution of the existing
Coreso and TSC coordinators
–
in this case, it could be natural to have a set up with two
locations within a ROC (e.g. Munich and Brussels, if current coordinadors were to keep
existing locations).
The benefits and shortcomings of
Option 2
would be similar to those of Option 1 as the
geographical scope of both options would be the same.
Option 3
would entail that the EU ISO is responsible for performing all the functions at
EU level. This approach would lead to efficiency gains, as it would no longer be necessary
to ensure the coordination and cooperation between entities at regional level and all the
functions could be performed seamlessly. However, it is questionable whether from a
technical point of view, at this stage, a single entity would be capable of carrying out all
these functions at EU level even if it envisages setting up sub-regional desks for the more
detailed assessment of regions.
(iii)
Decision-making competences
In
Option 0,
RSCs have a purely advisory role i.e. the recommendations that they issue
can be overriden by TSOs
75
. This would be the option less politically sensitive. However,
this can potentially lead to inefficient outcomes. 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 in the form of recommendations are non-
binding. These decisions can be considered as an input that can be rejected 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 their national framework
(e.g., in the case of cross-border remedial actions, a TSO may be obliged to reject the
recommendations issued by the ROC given that the national framework requires a different
order of implementation of remedial actions).
74
75
This would also pave the way for a further long term evolution towards Regional Independent System
Operatiors.
Indeed, coordination between TSOs through RSCs could be successful if the national frameworks were
harmonised. However, since national frameworks may differ significantly, voluntary coordination is not
likely to be optimal in the medium term.
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In
Option 1
ROCs would have an enhanced advisory role for all functions. Under this
option, ROCs could be entrusted with certain decision-making competences (as opposed
to a pure service provision role) to avoid the possibility of regional optimisation being lost
due to national constraints. This approach is likely to lead to more efficient outcomes since
there would be a margin for overcoming obstacles deriving from the national framework
(e.g. remedial actions, capacity calculation). In the case of the example above, when
deciding about the commercial cross-border capacities in a given region which are already
calculated at regional level, the decisions taken by ROCs could be final and binding. Whilst
this option is likely to bring more efficient outcomes, it is also likely to be more politically
controversial, especially with TSOs and Member States. However, other stakeholders have
expressed support for this option
76
. This could be done either directly enshrining the
functions in legislation or subsequently by mutual agreement of the NRAs overseeing a
certain ROC.
In
Option 2
with RISOs that can fully take over system operation at regional level, all
functions carried out by RISOs would be binding since they would fully replace the
functions performed at national level. Entrusting decision making powers to RISOs would
be justified based on the fact that system operation decisions might span well beyond the
area of a single TSO and affect the whole system. This would be the basis for a regional
system operation
77
. However, this option would be extremely sensitive politically and
would likely be rejected by many Member States.
Option 3
would require entrusting the performance of the functions and associated
decision-making powers to a single entity, the EU ISO, who would take binding decisions.
This option would set the basis for a truly European operation of the electricity system.
While there would be additional efficiency gains compared to those resulting from Option
2 (e.g., it would no longer be necessary to ensure the coordination of operations of a
number of entities at regional level), it is unclear whether this option is technically feasible
at this stage. Option 3 would also be politically unacceptable.
76
77
Eurelectric has recently pointed out that
"A step-wise regional integration of system operation and of
planning tasks relevant to cross-border trade therefore needs to happen. Such a process should build
upon the ongoing establishment of RSCs, which are executing a certain number of system operation
tasks on behalf of the national TSOs and could be a step towards gradually allocating the responsibility
for those tasks to regional entities".
Eurelectric,
"Develop a regional approach to system operation",
June 2016. Also, in response to the Commission Public Consultation on a new energy market design,
Acciona emphasised that
"system operation should be coordinated at the same level as markets are, to
efficiently manage electricity systems as an integrated whole. Therefore, a regional responsibility for
system security should gradually replace national responsibilities".
Also in its response to the Public
Consultation, Engie submitted that
"current national responsibility for system operation indeed hampers
cross-border cooperation and is not mimicking the progress made on side of market integration:
different capacity calculation in the flow based approaches are leading to lower capacity"
and that it
"favours closer cooperation of TSOs and RSCs taking over new functions progressively (eventually
replacing national TSOs in those functions). Stepwise approach is needed."
In its response to the Public
Consultation, Business Europe has stated that
"establishing regional system operators, based on a costs-
benefits analysis, could be a first step towards more operational coordination of TSOs in the future".
In this regard, Eurelectric has highlighted that
"A truly regional system operation can however only be
based on a regional decision-making structure and a single operational framework. Establishing
regional integrated system operators performing system operation and planning tasks in all regions
should therefore be the end goal to allow for more operational coordination of TSOs".
Eurelectric,
"Develop
a regional approach to system operation",
June 2016
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(iv)
Institutional layout/Governance
Option 0
would not require significant institutional changes, as the interaction between
RSCs, NRAs, TSOs, ACER and ENTSO-E would remain as set out in the System
Operation Guideline.
Option 1
would require increasing the level of cooperation between
NRAs and governments, as well as additional competences for ACER and ENTSO-E, to
ensure the oversight of ROCs.
Options 2 and 3
would each require substantial changes to
the institutional framework in order to encompass the switch of decision-making powers
for system operation from a national to a regional or EU-wide level. The costs and speed
of implementation would also increase for each of the options, being Option 3 the most
costly and most timely.
(v)
Conclusion of evaluation
The Table below provides a qualitative comparison of the Options in terms of their
effectiveness, efficiency and coherence of responding to specific criteria.
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Table 1:
(The assumptions in this table are based on the feedback received from
stakeholders in their response to the public consultation and from additional submissions
from ACER).
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Criteria
Option 0:
BAU
0/+
Progress remains
limited due to
zones not based
on technical
operation of the
grid
+
Can build upon
established
structures
(RSCIs)
Quality
Speed
of
implementation
Option 1:
ROC
approach
+
More efficient
as optimisation
over zones
based on
technical
operation of the
grid
0
Can partially
build upon
established
structures;
change in
geographical
scope and
functions
Option 2:
RISO approach
++
Very efficient
because of enhanced
system operation at
regional level
Option 3;
EU ISO approach
+++
Most efficient because
of seamless system
operation at EU level
Use
of
established
institutional
processes
++
Can build upon
established
structures (no
decision-making
responsibility)
-
Requires
building up
new structures/
processes
(possibly some
decision-
making
responsibility)
+
Enhanced
cooperation via
ROCs; reduced
risk of blackout
++
Efficient
organisational
structure can be
created; all
services for a
region carried
out by one
company
--
Can partially build
upon established
structures but it will
require a substancial
centralization at
regional level;
change in
geographical scope
of functions; it
would require a
substantial amount
of time for
implementation.
--
Requires building
up new structures/
processes (decision-
making
responsibility for all
regional relevant
functions)
++
Integration via
RISOs; significantly
reduced risk of
blackout
+++
Efficient
organisational
structure can be
created; all services
for a region carried
out by one company
---
Cannot build on
established structures.
Substantial change in
geographical scope of
functions. It would
require a substantial
amount of time for
implementation
Secure
operation of the
network
Efficient
organisational
structure
0/+
Mandated
cooperation;
slightly reduced
risk of blackout
-
Sub-optimal
organisational
structure; a given
region can get
services from
different
providers
---
Requires building
additional structures
and processes that are
adapted for the
operation of this entity
at EU level (decision-
making
responsibilities for all
functions at EU level)
+++
Seampless operation
at EU level;
significantly reduced
risk of blackout
+++
Efficient
organisational
structure can be
created; all services at
EU level carried out
by a single company
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Political
sensitivity
0
Politically most
acceptable as it
represents the
convergence
achieved during
discussions with
Member States
and stakeholders
for the System
Operation
Guideline
-
Politically
sensitive due to
shift in
decision-
making
responsibility
for relevant
functions
--
Extremely
politically sensitive
due to shift in
decision-making
responsibility
---
Politically
unacceptable at this
stage
In summary:
While
Option 0
will allow achieving some progress in terms of regional coordination
which might be sufficient in the short to medium term, it risks falling short and being
suboptimal in the post 2020 context with the subsequent negative consequences in terms
of system security and market efficiency
78
. It would also affect the effectiveness of many
of the other proposals of the market design initiative and be a missed opportunity to
propose legislation on the field that can shape the EU power system in the future.
Option 1
is the preferred option to respond to the post 2020 challenges in system operation.
Execution of the additional functions as outlined in Option 1 will lead to the ROCs
approach, featuring benefits in efficiency and security, but also leading to increased needs
for resources at regional level (data systems, experienced staff). Allowing ROCs to be
entrusted with certain decision-making responsibilities (as opposed to a pure service
provision role) will avoid the possibility of regional optimisation being lost due to
constraints resulting from differences in the national frameworks. This option enhances
the effectiveness of many other proposals of the market design initiative.
Option 2
and
Option 3
would constitute the most preferable options from the point of
view of seamless system operation, efficiency and economic gains. While they should not
be discarded as a direction that should be followed in the future, none of these options are
considered proportionate at this stage. Moreover, the feasibility of Option 3 is
questionable. Option 2 is supported by some stakeholders as a long-term goal
79
.
78
79
Eurelectric shares this view and has recently stated that "Current
TSOs coordination initiatives such as
RSCs are steps in the right direction. The harmonisation and integration requirements developed in the
System Operation Guideline are nevertheless not ambitious enough. Indeed, these approaches remain
mostly national with the aim to protect the autonomy of individual system operators. Most importantly,
those initiatives do not fully equip system operators to cope with the challenges of a low-carbon power
power system".
Eurelectric,
"Develop a regional approach to system operation",
June 2016
For example, Eurelectric declares that
"A truly regional system operation can however only be based
on a regional decision-making structure and a single operational framework. Establishing regional
integrated system operators performing system operation and planning tasks in all regions should
therefore be the end goal to allow for more operational coordination of TSOs".
Moreover, it states that
"The transistion towards a truly integrated and decarbonised elecricity market will be more efficient if
the electricity system is optimised on a regionla and ultimately a European basis (e.g. TSOs should
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Figure 3 below describes a stepwise approach for the implementation of the future
ROCs
Source: Commission.
Subsidiarity
The subsidiarity principle is respected given that the challenges the EU power system will
be facing in the post 2020 context are pan-European and cannot be addressed and optimally
managed by individual TSOs. While the mandated TSO cooperation via the establishment
of Regional Security Coordinators (RSCs) envisaged in the System Operation Guideline
constitutes a positive step forward because they will play an increasingly important support
role for TSOs, the full decision-making responsibility will remain with TSOs. This
framework will however not suffice to address the reality of the dynamic and variable
nature of the future electricity system, in which stressed system situations will become
more frequent. This is why it would be required to make the concept of RSCs further evolve
towards the creation of ROCs, centralising some functions over relevant geographical
areas.
The creation of ROCs and allocation of competences to these entities would also be in line
with the proportionality principle given that it does not aim at replacing national TSOs but
rather at complementing the functions which have regional relevance and cannot be
optimally performed in isolation any longer. The competences of ROCs will be limited to
operate the system as "one"). This will require a high degree of cooperation between system operators
and the harmonisation of system operation rules. […] Establishing regional integrated system operators
performing system operation and planning tasks in all regions should therefore be the end goal to allow
for more operational coordination of TSOs".
Eurelectric, "Develop
a regional approach to system
operation",
June 2016. In addition, in response to the Commission public consultation on a new energy
market design, Fortum submitted that
"the goal should be that the market, in practice, sees only one
TSO. It could be done by [an] European TSO or by current TSOs improving their cooperation".
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specific operational functions at regional level, for cross-border relevant issues in the high
voltage grid and will exclude real-time operation.
Stakeholders' opinions
Based on the results of the Public Consultation, as concerns the proposal to foster regional
cooperation of TSOs, a clear majority of stakeholders is in favour of closer cooperation
between TSOs. Stakeholders mentioned different functions which could be better operated
by TSOs in a regional set-up and called for less fragmentation in some important work of
TSOs. Around half of those who want stronger TSO cooperation are also in favour of
regional decision-making responsibilities (e.g. for Regional Security Coordinators). Views
were split on whether national security of supply responsibility is an obstacle to cross-
border cooperation and whether regional responsibility would be an option.
The participants to the European Electricity Regulatory Forum have also recently
emphasised the need for closer cooperation between TSOs, enlarging the scope of
functions and optimising the geographical coverage of regional centres. It recognised,
however, that there were divering opinions as regards the delineation of responsibilities
between regional centres and national TSOs and that further consideration was needed
80
.
The creation of Regional Operational Centres will be likely seen with concern by TSOs
and a large number of Member States which seem to consider that the currently foreseen
cooperation via Regional Security Coordinators is fit for purpose. In particular, Member
States are likely to oppose any step oriented to entrust regional structures with decision
making powers under the assumption that security of supply is a national responsibility.
Regarding the regions, Member States might prefer geographical dimensions based on
governance rather than what would be optimal from a technical point of view.
80
See
Florence
Forum
conclusions
of
March
2016:
https://ec.europa.eu/energy/sites/ener/files/documents/Conclusions%20-%20Florence%20Forum%20-
%20Final.pdf
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3. D
ETAILED
MEASURES ASSESSED UNDER
P
ROBLEM
A
REA
I,
OPTION
DEMAND RESPONSE AND DISTRIBUTED RESOURCES INTO THE MARKET
1(
C
); P
ULLING
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3.1. Unlocking demand side response
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Summary table
Objective: Unlock the full potential of demand response
Option O: BAU
Option 1: Give consumers access to
technologies that allow them to participate
in price based demand response schemes
Stronger enforcement of existing
Give each consumer the right to request the
legislation that requires Member
installation of, or the upgrade to, a smart
States to roll out smart meters if a
meter with all 10 recommended
cost-benefit analysis is positive and
functionalities.
to ensure that demand side resources
Give the right to every consumer to request
can participate alongside supply in
a dynamic electricity pricing contract.
retail and wholesale markets
No new legislative intervention.
This option will give every consumer the
right and the means (fit-for-purpose smart
meter and dynamic pricing contract) to fully
engage in price based DR if (s)he wishes to
do so.
Roll out of smart meters will remain
limited to those Member States that
have a positive cost/benefit analysis.
In many Member States market
barriers for demand response may not
be fully removed and DR will not
deliver to its potential.
Roll out of smart meters on a per customer
basis will not allow reaping in full system-
wide benefits, or benefits of economies of
scale (reduced roll out costs)
Incentive based demand response will not
develop across Europe.
Option 2: as Option 1 but also fully enable
incentive based demand response
In addition to measures described under Option
1, grant consumers access to electricity markets
through their supplier or through third parties
(e.g. independent aggregators) to trade their
flexibility. This requires the definition of EU
wide principles concerning demand response
and flexibility services.
This option will allow price and incentive
based DR as well as flexibility services to
further develop across the EU. Common
principles for incentive based DR will also
facilitate the opening of balancing markets for
cross-border trade.
As for Option 1, access to smart meters and
hence to price based DR will remain limited.
Member States will continue to have freedom
to design detailed market rules that may hinder
the full development of demand response.
Option 3: mandatory smart meter roll out and full
EU framework for incentive based demand
response
Mandatory roll out of smart meters with full
functionalities to 80% of consumers by 2025
Fully harmonised rules on demand response
including rules on penalties and compensation
payments.
This guarantees that 80% of consumers across the
EU have access to fully functional smart meters by
2025 and hence can fully participate in price based
DR and that market barriers for incentive based
DR are removed in all Member States.
It ignores the fact that in 11 Member States the
overall costs of a large-scale roll out exceed the
benefits and hence that in those Member States a
full roll-out is not economically viable under
current conditions.
Fully harmonised rules on demand response
cannot take into account national differences in
how e.g. balancing markets are organised and may
lead to suboptimal solutions.
Most suitable option(s): Option 2.
Only the second option is suited to untap the potential of demand response and hence reduce overall system costs while respecting subsidiarity
principles. The third option is likely to deliver the full potential of demand response but may do so at a too high cost at least in those Member States where the roll out of smart meters is not
yet economically viable. Options zero and one are not likely to have a relevant impact on the development of demand response and reduction of electricity system cost.
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Description of the baseline
For the purpose of this exercise a clear distinction has to be made between technological
prerequisites and market arrangements for demand response as those aspects are regulated
separately. As such chapter 3.2.1 will focus on the baseline for smart metering and 3.2.2
on dynamic prices and market regulation.
3.1.2.1. Smart Metering
Current Legislation on Smart Metering
Smart metering is a key element in the development of a modern, consumer-centric retail
energy system which encompasses active involvement of consumers. In recognition
hereof, provisions were included in the Gas Directive and in the Electricity Directive
fostering the smart metering roll-out and targeting the active participation of consumers in
the energy supply market. These provisions were then complemented with provisions
under the Energy Performance in Buildings Directive, and the Energy Efficiency Directive.
The Electricity and Gas Directives
81
require Member States to ensure the implementation
of intelligent metering systems that shall assist the active participation of consumers in the
energy supply market, and encourage decentralised generation
82
, and promote energy
efficiency. Article 3 (11) of the Electricity Directive and Article 3(8) of the Gas Directive
explicitly state that
“in order to promote energy efficiency, Member States or, where a
Member State has so provided, the regulatory authority shall strongly recommend that
electricity (or natural gas) undertakings optimise the use of electricity (or gas), for
example by providing energy management services, developing innovative pricing
formulas, or introducing intelligent metering systems or smart grids, where appropriate.”
This implementation may be conditional, according to Annex I.2 of both the electricity and
gas Directive, on a positive economic assessment of the long-term cost and benefits to be
completed by 3 September 2012. For electricity, the roll-out can be limited to 80% by 2020
of those positively assessed cases as potentially indicated in a cost-benefit analysis ('CBA').
Furthermore, Member States, or any competent authority they designate, are obliged
according to the Electricity and Gas Directive (Annex I.2) to “ensure
the interoperability
of those metering systems to be implemented within their territories”
and to “have
due
regard to the use of appropriate standards and best practice and the importance of the
development of the internal market”
in electricity or natural gas, respectively.
The recast of the Energy Performance of Building Directive ('EPBD'), adopted in May
2010, obliges (Art 8(2)) Member States to "encourage
the introduction of intelligent
metering systems whenever a building is constructed or undergoes major renovation,
whilst ensuring that this encouragement is in line with point 2 of Annex I to
[the Electricity
Directive]".
81
82
Annex I.2 of the Electricity Directive and of the Gas Directive.
Specifically for electricity and linked to smart grid deployment - Electricity Directive, recital (27)
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To assist with the preparations for the roll-out, and based on lessons learned and good
practices identified through experiences accumulated in Member States, the Commission
adopted the Recommendation on preparations for the roll-out of smart metering systems
83
.
It aimed at guiding Member States in their choices, drawing particular attention to: (i) key
functionalities for fit-for-purpose and pro-consumer arrangements
84
; (ii) data protection
and security issues; and (iii), a methodology for a CBA that takes account of all costs and
benefits, to the market and the individual consumer, of the roll-out. Following this
Recommendation, complementary smart metering provisions were adopted as part of the
Energy Efficiency Directive
85
.
Smart Metering Deployment in Member States
According to data from the Commission Report
"Benchmarking smart metering
deployment in the EU-27",
as also recently updated
86
, to date 19 Member States have
committed to rolling out close to 200 million smart meters for electricity by 2020 at a total
potential investment of EUR 35 billion.
-
17 Member States - Sweden, Italy, Finland, Malta, Spain, Austria, Poland, UK-GB,
Estonia, Romania, Greece, France, Netherlands, Denmark, Luxembourg, Ireland,
and lately Latvia
–
are targeting a nation-wide roll-out to at least 80% of customers
by 2020 (with 13 of them going much beyond the target of the Electricity
Directive).
-
2 Member States
–
Germany, Slovakia - are moving to deployment in a selected
segment of consumers (to max. 23% by 2020).
-
The rest 9 Member States have either decided against at least under current
conditions, or have not made a firm commitment yet for a mass-scale or even a
selective roll-out.
By 2020, it is projected that almost 72% of European consumers will have a smart meter
for electricity
87
. Smart meters for electricity are already being rolled out across the EU. As
of 2013, nearly all consumers in Sweden, Finland and Italy, were equipped with smart
meters.
Despite the progress noted, these implementation plans are falling short of the legislation's
intentions. For various legal and technical reasons, the current advancement is rather slow
83
84
85
86
87
Commission Recommendation on preparations for the roll-out of smart metering systems (2012)
http://eur-lex.europa.eu/legal-content/EN/ALL/?uri=CELEX:32012H0148
When it comes to functionalities for electricity smart metering, particularly important for residential
consumers are: a readings' update rate of 15 minutes and a standardised interface to transfer and visualise
individual consumption data in combination with information on market conditions and service or price
options.
Energy Efficiency Directive. Art 9(2), 12(2b)
"Status report based on a survey regarding Interoperability, Standards and Functionalities applied in
the large scale roll-out of smart metering in EU Member States"
(2015) Smart Grids Task Force Expert
Group
1;
https://ec.europa.eu/energy/sites/ener/files/documents/EG1_Final%20Report_SM%20Interop%20Stan
dards%20Function.pdf
Report from the Commission
"Benchmarking smart metering deployment in the EU-27 with a focus on
electricity"
(2014)
http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=COM%3A2014%3A356%3AFIN
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–
particularly in view of the fast approaching 2020 target in the case of electricity
–
and
the progress gap to delivery may be further widened by recurring delays in national
programmes
88
. In addition, there is a risk that the systems being rolled-out do not bring all
the desired benefits to consumers and the market as a whole as they do not include the
necessary functionalities to do so. Furthermore, they might not support in all cases
standardised interfaces
89
–
at home or station level
–
for the delivery of these
functionalities, nor be complemented with additional specifications for improving
interoperability on these interfaces and the smooth exchange of information and inter-
working between the metering infrastructure and devices or other network platforms in the
energy market.
In all cases, the successful roll-out is controlled to a large extent by Member States who
are ultimately responsible for the deployment and respective market arrangements
90
, and
may or may not decide to follow the guidelines tabled by the Commission regarding
functionalities and implementation measures for data privacy and security (see Energy
Efficiency Directive (Art 9(2b)) and Commission Recommendations "on the preparations
for the roll-out of smart metering systems", and "on the data protection impact assessment
template for smart grids and smart metering systems"
91
).
3.1.2.2. Market arrangements for demand response
Legislative Background
Mechanisms to remove the barriers to demand flexibility are set out in the Electricity
Directive. The Energy Efficiency Directive ('EED') builds on those provisions and
elaborates further, promoting its access to and participation in the market and the removal
of existing barriers.
The Electricity Directive refers to demand response measures as a means to pursue a wide
range of system benefits. The Directive clearly identifies demand response as an alternative
to generation to be considered on an equal footing, e.g. when Member States are launching
tendering procedures for new capacity in situations where the resource adequacy is
insufficient to ensure security of supply (e.g. Art. 8 Electricity Directive). Demand
response, alongside energy efficiency, is viewed as one of the measures to combat climate
change and ensure security of supply. Demand response is recognised as a means to
provide ancillary services to the system in the provisions related to TSO tasks (Art. 12(d)
Electricity Directive), and demand side management/energy efficiency measures must be
considered as an investment alternative in the context of distribution network development
by DSOs planning for new grid capacity (Art. 25(7) Electricity Directive).
88
89
90
91
See the Smart Metering Annex of Market Design Evaluation.
"Status report based on a survey regarding Interoperability, Standards and Functionalities applied in
the large scale roll-out of smart metering in EU Member States"
(2015) Smart Grids Task Force Expert
Group 1.
Commission Staff Working Document
"Cost-benefit analyses & state of play of smart metering
deployment in the EU-27"
(2014), sections 2.4 and 2.7
http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX%3A52014SC0189
"Commission
Recommendation on the Data Protection Impact Assessment Template for Smart Grid and
Smart Metering Systems"
(2014)
http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=uriserv%3AOJ.L_.2014.300.01.0063.01.ENG
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Effective price signals are important to encourage efficient use of energy and demand
response. In this context, recital 45 of the EED indicates that Member States should ensure
that national energy regulatory authorities are able to ensure that network tariffs and
regulations support dynamic pricing for demand response measures by final customers.
Under Art. 15(1) EED, Member States must ensure that network regulation and tariffs meet
criteria listed in Annex XI of the EED, which
inter alia
refer to different possibilities for
network and retail tariffs to support dynamic pricing for demand response and incentivise
consumers. According to Article 15(4) EED, Member States must ensure the removal of
those incentives in transmission and distribution tariffs that might hamper participation of
demand response in balancing markets and ancillary services procurement. Most relevant
in the context of this impact assessment is however, Article 15(8) EED. In summary,
Member States must comply with the following obligations:
-
Ensure that national energy regulatory authorities encourage the participation of
demand side resources, including demand response, alongside supply in wholesale
and retail markets;
Ensure
–
subject to technical constraints inherent in managing networks - that TSOs
and DSOs treat demand response providers, including demand aggregators in a
non-discriminatory way and on the basis of their technical capabilities;
Promote - subject to technical constraints inherent in managing networks - access
to and participation of demand response in balancing, reserve and other system
services markets, requiring that the technical or contractual modalities to promote
participation of demand response in balancing, reserve and other system services
markets - including the participation of aggregators - be defined;
Ensure the removal of those incentives in transmission and distribution tariffs that
might hamper participation of demand response in balancing markets and ancillary
services procurement
92
.
-
-
-
Situation in Member States with regards to demand response
The EU demand response market is still in its early development phase. This early
development has proceeded very differently across Member States that have chosen
different approaches to make use of demand side flexibility and to implement demand
response. In fact, while Article 15.8 EED formulates principles for the market access of
demand service providers and demand side products it has left substantial freedom for
Member States to implement these.
While a full transposition check of Art 15.8 EED has not yet been carried out it can already
be seen that different national provisions have led to a fragmented European market on
demand response with different rules and market opportunities for (independent) demand
response service providers, different market arrangements between service providers and
balancing responsible parties (including compensation payments) and different rules for
trading flexibility in the balancing, wholesale and capacity markets.
Explicit (or incentive based) demand response
92
See guidance note on Energy Efficiency Directive Art 15 which also covered Industrial Emissions
Directive elements
http://eur-lex.europa.eu/legal-content/EN/ALL/?uri=CELEX:52013SC0450
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For explicit demand response, full customer participation in the electricity markets is a
prerequisite as addressed in the relevant provisions of the EED. However, because of its
complexity only very large industrial consumers can directly engage in the electricity
markets while commercial and residential consumers will in most of the cases need to go
through demand response service providers (aggregators). These require fair market access
for such aggregators and open balancing, wholesale and capacity markets for flexibility
products.
a) Market Access for aggregators
The EED stipulates that demand response providers (including aggregators) have to be
treated in a non-discriminatory manner. However, market access and market rules for
aggregators are regulated differently across Europe. In order to ensure full access to the
market at least the following main features have to be addressed in national regulation:
-
Clear definition of roles and responsibilities of aggregators within the energy
market to ensure legal certainty;
-
Clear definition of the relationship between aggregators and Balancing
Responsible Parties ('BRPs') that ensures market access of the aggregators at fair
conditions. Such rules are essential to ensure that the BRP (which is usually the
supplier) has no means of stopping a competitor (e.g. independent aggregator) for
engaging with one of its customers and entering the market.
In many Member States such a framework for aggregators is effectively missing or
independent aggregation is legally banned. This applies for Bulgaria, Croatia, Cyprus,
Czech Republic, Estonia, Greece Italy, Malta, Portugal, Spain and Slovakia. But also in
Member States where legislation for aggregators and demand response has been
established many differences can be noted.
To date, France is the only Member State that developed a complete framework for demand
response explicitly enabling independent aggregation by guaranteeing contractual freedom
between the consumer and the aggregator without supplier's consent. A standardised
framework also exists for the compensation mechanisms, however, it is claimed by some
stakeholders that this mechanism greatly penalises the aggregator, overcompensates the
BRP and hence renders the business case for independent aggregators negative.
Other Member States allow (independent) aggregation but to varying degrees. Independent
aggregators are allowed in Belgium, Ireland, UK, Germany and Austria albeit not all
markets are effectively opened to them as rules, e.g. in Austria, effectively limit their
activity to aggregate loads of big consumers. In some Member States like Poland, the
Netherlands and in the Nordic markets aggregators have also to become suppliers or offer
their services jointly with suppliers but cannot act as completely independent service
providers. In all Member States, apart from France, the UK and Ireland, the explicit consent
of the consumer's supplier is required for aggregators to enter into the market. Equally in
those Member States, a clear framework for compensation payments is missing and
therefore such payments may need to be individually negotiated between the independent
aggregator and supplier as a precondition for accessing the consumer. As such, the
incumbent supplier can effectively block market access at least for independent
aggregators.
b) Access of flexibility to the markets
The EED requires Member States to promote access to and participation of demand
response in balancing, reserve and other system services markets
inter alia
by engaging
the national authorities (or where relevant, the TSOs and DSOs) to define technical
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modalities on the basis of the technical requirements of these markets and the capabilities
of demand response; these specifications must include the participation of aggregators.
Technical modalities or requirements can be for example the minimum size of a load, the
activation time or the duration for which a product needs to be provided. Traditionally,
requirements have been designed along the capacities of big generation units, e.g. coal
power plants. Demand side products naturally face problems to meet these requirements,
even if aggregated. Another aspect is that prequalification requirements often have to be
fulfilled per unit and not at the aggregated level. As the following stock-taking will show,
access of demand resources to the wholesale, balancing and recently capacity markets
varies considerably across Member States.
The analysis of the
status quo
suggests that in most of the Member States access to the
markets is either up-front restricted or preconditions make it difficult for demand side
products to qualify and compete. In roughly only a third of the Member States demand side
products have fair access to the markets and in even fewer Member States demand response
is actually happening. Generally, the balancing markets tend to be more open to demand
side products than the wholesale markets.
In many Member States demand side resources do not play any role in the markets.
Examples for this situation would be Cyprus, Malta and Croatia. But also in many other
Member States markets are practically closed and allow for only very restricted
participation of the demand side. Often it is only suppliers or big industrial actors that are
allowed to bid in the markets. In those cases, there are usually very specific demand
flexibility programmes for selected, mainly very large, actors. For example, in Italy, Spain
and Greece interruptibility programmes have been or are being introduced for large
industrial loads.
Other countries are one step ahead and have partly opened their markets, while practical
barriers still hamper the market access. The balancing market in Germany for example is
in principle open to demand loads, but heavy prequalification (e.g. extensive testing) and
programme requirements (e.g. bid size) block any major remand response-activity.
Similarly, practical barriers, in particular for aggregated demand, hamper access to the
–
theoretically open
–
balancing markets in Slovenia and Denmark and to some degree also
in Sweden.
There is a group of countries where demand response has already assumed a more
important role. Belgium for example adapted their technical requirements and offers quite
a large range of possibilities for demand side resources to participate in the balancing and
ancillary services markets. In the UK, the market for ancillary services
93
is open to demand
response and a dedicated 'Demand Side Balancing Reserve' mechanism was established in
2015. Meanwhile, France has become probably the Member State with the broadest general
access of demand response to both the balancing and the wholesale market. A general
framework is in place that facilitates demand side participation, which has caused demand
response providers to begin expanding onto this market.
The table below summarizes in which Member States markets are open to demand
response and the amount of incentive based demand response currently estimated in those
93
The range of functions which TSOs contract so that they can guarantee system security, including black
start capability, frequency response, fast reserve and the provision of reactive power.
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Member States. While demand response is allowed to participate in most Member States,
activated volumes of more than 100 GW can only be found in 13 Member States.
Table 1: Uptake of incentive-based demand response
Member State
Demand Side
Products (DSP) in
energy markets
DSP in balancing
markets
DSP in capacity
mechanisms
Estimated
demand
response for
2016 (in GW)
104
689
0
0
0
49
566
0
810
1689
860
1527
30
48
4131
7
0
Austria
Yes
Yes
Belgium
Yes
Yes
Yes
Bulgaria
No
No
Croatia
No
No
Cyprus
No market
No market
Czech Republic
Yes
Yes
Denmark
Yes
Yes
Estonia
Yes
No
Finland
Yes
Yes
Yes
France
Yes
Yes
Yes
Germany
Yes
Yes
Yes
Greece
No (2015)
No
Hungary
Yes
Yes
Ireland
Yes
Yes
Yes
Italy
Yes
No
Yes
Latvia
Yes
No
Yes
Lithuania
unclear
No
Luxembourg
No information
No information
Malta
No market
No market
Netherlands
Yes
Yes
170
Poland
Yes
Yes
No
228
Portugal
Yes
No
40
Romania
Yes
Yes
79
Slovakia
Yes
Yes
40
Slovenia
No
Yes
21
Spain
Yes
No
Yes
2083
Sweden
Yes
Yes
Yes
666
UK
Yes
Yes
Yes
1792
Total
15628
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering"(2016) COWI
Implicit (price based) demand response
For implicit demand response, smart metering systems as well as the availability of
dynamic pricing contracts linked to the wholesale market are prerequisites. For smart
metering systems roll-out plans exist for 17 Member States, while in 2 Member States a
partial roll-out is planned and in a number of those Member States the functionalities of
the smart metering systems (enabling communication interfaces, frequent update intervals,
advanced tariffication, etc.) may not allow for automatically reacting to price signals (a
complete analysis is provided within the evaluation fiche on smart metering). EU
legislation does not currently impose any requirements on Member States to activate price
based (or implicit) demand response.
In order to activate price based demand response the availability of dynamic electricity
pricing contracts are a prerequisite as those contracts can incentivise consumers to adjust
their consumption according to the real time price signal. The ACER/CEER Market
Monitoring Report contains a dedicated analysis of the competition situation in all Member
States in the retail market and the different offers available to the customers. This analysis
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shows that only in Denmark, Sweden and Finland dynamic pricing contracts that are linked
to the spot market are available to residential consumers while only in Sweden and Norway
such contracts represent more than 10% of all consumer contracts. In terms of costs for the
consumers the ACER/CEER analysis shows that offers linked to the spot market are
slightly cheaper for the consumer than fixed or variable offers in the same country.
Graph 1: Type of energy pricing of electricity offers in EU Member States capital
cities,
Source: "Market Monitoring Report 2014" (2015) ACER
In addition to the three Member States addressed above also in Estonia, Spain, Austria,
Belgium, Netherlands and Germany dynamic pricing contracts are available on the market
–
at least for certain consumer groups - which were not yet included in the ACER/CEER
analysis. However, the uptake of such tariffs is currently very low and no detailed data is
available yet.
As a high level estimate for the EU, studies and data support current load shifting due to
times of use tariffs and price based demand response ranging from negligible (most
Member States), to around 1% (most Northern European Countries) to 6-7% (Finland and
France). The overall load that is shifted due to Time-of-Use ('ToU') and dynamic tariffs to
date would be of the order of 5.7GW (or 1.2% of peak load in Member States where
dynamic tariffs are offered).
While data on current demand response levels is difficult to obtain, estimates from the
impact assessment study
94
indicate the use of approx. 21.4 GW of demand response per
year in Europe including the 5.7GW from ToU and dynamic tariffs referred to above. This
is only a small fraction of the demand response potential that adds up to approx. 120.000
MW in 2020 and 160.000 MW in 2030 which will lay mainly with residential consumers.
However, this potential is purely theoretical (not taking into account commercial viability
and technology restriction) and for 2030 greatly depends on the uptake of flexible loads
such as electric vehicles and heat pumps in the residential sector.
94
"Impact Assessment support Study on downstream flexibility, demand response and smart metering",
(2016) COWI
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Graph 2: Theoretical demand response potential 2030
50000
45000
40000
35000
30000
25000
Industrial
20000
15000
10000
5000
0
Commercial
Residential
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart metering"
(2016) COWI
Deficiencies of current legislation
A detailed analysis of the existing legislation on smart metering systems and demand
response in European and national legislation has been carried out in the framework of the
evaluation. The detailed results of this analysis are reported in the annexes to the Market
Design Initiative evaluation (annexes on "Details on the EU framework for smart metering
roll-out and use of smart meters" and "Details on the EU framework for Demand Side
Flexibility")
3.1.3.1. Deficiencies of current Smart Metering Legislation
Looking at the current situation with smart metering deployment in the Member States,
despite the progress noted, EU-wide implementation is falling short of the legislator's
intentions, in terms of level of commitment, roll-out speed, and purpose. In the light of the
developments so far, the existing provisions can be assessed as follows.
In terms of
effectiveness,
the evidence available generally suggests that the smart metering
provisions currently in place have been less effective than intended. This is partly a result
of the 'soft'/unspecific nature of some obligations they lay (i.e. Article 8(2) of the EPBD.
Enforcing the recommended
95
minimum functionalities for smart metering systems on an
EU level, and consistently promoting the use of available standards to ensure connectivity
and 'interoperability', as well as best practices, while having due regard to data security
and privacy, would guarantee a coherent, future-proof system able to support novel energy
services and deliver benefits to consumers, in line with the legislator's intentions.
95
Commission Recommendation on preparations for the roll-out of smart metering systems (2012)
http://eur-lex.europa.eu/legal-content/EN/ALL/?uri=CELEX:32012H0148
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There is not enough evidence at the moment to evaluate the
efficiency
of the intervention
in terms of proportionality between impacts and resources/means deployed. This is due to
the fact that most of the large-scale roll-out campaigns have yet to start unfolding making
the field data available rather scarce; there are only projections available based on Member
States cost-benefit assessments.
In terms of
relevance,
the evaluated smart metering provisions, considering current needs
and problems, remain highly valid. This said, they could though be further enhanced, by
elaborating them as to: (i) spell out how the term of
'active participation'
is to be
understood, and expected to be realised in practical terms, namely define requirements for
functionality, connectivity, interoperability, and standards to use; (ii) include an obligation
to Member States to officially set the minimum technical and functional requirements for
the smart metering systems to be deployed, the market arrangements, and clarify the
roles/responsibilities of those involved in the roll-out.
In terms of
coherence
–
internally and with other EU actions
–
even though no clear
contradictions could be pointed out, the evaluation has identified some room for
improvement. Linking of the term
'actual time of use'
in Article 9(2a) and Article 9(1) EED
to smart metering provisions erroneously restricts the functional requirements of the
targeted set-ups and raises questions about coherence with the framework for promoting
smart meters. There is therefore a need to clarify that a wide range of functionalities is in
fact promoted, as those recommended by the Commission, that go much beyond the
capability of just
'actual time of use'
information which usually refers to advanced, and not
smart metering.
Finally, evidence points to the need to eliminate ambiguities and to further elaborate,
clarify, and even strengthen the existing provisions, in order to give certainty to those
planning to invest and ensure that smart metering roll-outs move in the right direction, and
regain
EU added-value.
This is to be done by: (i) safeguarding common functionality, and
share of best practices; (ii) ensuring coherence, interoperability, synergies, and economies
of scale, boosting competitiveness of European industry (both in manufacturing and in
energy services and product provision); and (iii), ultimately delivering the right conditions
for the internal market benefits to reach also consumers across the EU.
3.1.3.2. Deficiencies of current regulation on demand response
It was the objective of the existing European legislation to put demand response on equal
footing with generation and to ensure that demand response providers, including
aggregators, are treated in a non-discriminatory way. While provisions aiming at realising
those objectives have been put in place in many Member States, the development of
demand response across Member States varies significantly and has led to fragmented
markets. Especially the different treatment of independent aggregators across the EU is a
matter of concern. It can therefore be concluded that additional provisions further
specifying the existing provisions are needed to ensure a harmonised development and
enable price and incentive based demand response across Europe.
In terms of
effectiveness,
the evidence available generally suggests that the demand
response provisions currently in place have been less effective than intended. The
provisions have not been effective in removing the primary market barriers especially for
independent demand response service-providers and creating a level playing field for them.
Instead the heterogeneous development of demand response has led to fragmented markets
across the EU. This is mainly due to the high degree of freedom the existing provisions
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leave to Member States. The different treatment especially of independent demand
response service-providers in national energy markets as well as of flexibility products in
electricity markets risk undermining the large-scale deployment of demand response
needed as well as the functioning of the internal energy market.
There is not enough evidence at the moment to evaluate the
efficiency
of the intervention
in terms of proportionality between impacts and resources/means deployed.
In terms of
relevance,
the herein evaluated demand response provisions remain highly
valid. Full exploitation of demand response remains crucial to manage the energy transition
as it is an enabler for efficiently integrating variable renewables into the energy system.
However, as pointed out above, the existing provisions have not been effective in
deploying demand response sufficiently quickly across Europe.
In terms of
coherence
the evaluation has shown that the provisions on demand response
are fully coherent with other legislative provisions within the Electricity Directive, the
EED, the RED and the EPBD.
Finally, considering the
EU added value,
it remains crucial to ensure that harmonised
demand response provisions are in place across the EU to guarantee a functioning internal
energy market. Even more because under the upgrading of the wholesale market within
the market design initiative the Commission will also look into opening national balancing
markets where flexibility may then be traded across borders. Full availability of demand
response in all Member States will then be crucial for the functioning of those cross-border
balancing markets.
Presentation of the options
Option 0: BAU
As outlined in chapter 3 the existing provisions on smart meters and demand response have
not proven to be fully effective in reaching the goals of rolling out fully functional smart
metering systems to at least 80% of consumers EU-wide by 2020 and to put demand
response on equal footing with generation.
Option 0+: Non-regulatory approach
Considering non-legislative intervention and just resorting to Option 0+ of a potential
stronger enforcement and/or voluntary cooperation, would not allow for an improvement
of the current situation regarding the uptake of fit-for-purpose smart metering and of the
market conditions for demand response to flourish. Option 0+ is not expected to remove
market barriers for demand side flexibility to reach its full potential, and therefore will not
deliver the policy objectives.
According to the Commission's assessment, the provisions related to smart metering
systems have been correctly transposed in Member States and hence, as argued earlier, no
further enforcement leading to a greater roll out of such systems is realistic. The provisions
of Art 15(8) EED related to demand response have not yet been subject to a full
transposition check or any infringements. However, even in those Member States where
the provisions have been fully and correctly transposed market barriers for independent
service providers continue to exist. This suggests that the current provisions are not
sufficiently explicit to fully remove all remaining barriers to demand response. As such a
stronger enforcement of existing provisions may in some Member States lead to a greater
take up of demand response but this alone will not be sufficient to provide a full level
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playing field as intended by European legislation, and would not deliver the policy
objectives, which is the reason this option was not further considered.
Option 1: Enable price based demand response
Smart metering systems are the key prerequisite for properly accounting for, and then
rewarding, consumers' involvement in demand response or the use of distributed energy
resources. However, it is expected that a smart meter roll-out will be realised in only 17
Member States (plus a partial roll-out in 2 Member States). In some of those Member States
the roll-out may take place without all the functionalities identified in the Commission
Recommendation on the preparations for the roll-out of smart metering systems.
Our objective is to ensure that interoperable smart metering systems with the right
functionalities are available to all consumers. The policy measures to ensure that price
based demand response can develop include:
-
-
-
Give consumers the right to request a meter with the full 10 functionalities when
roll-out without full functionality is taking place or has already been completed.
Give consumers the right to request a smart meter with full functionalities when
wide scale roll-out is not carried out
96
.
Grant consumers the right to an electricity pricing contract linked to the
development of the spot market.
Option 2: Enable price and incentive based demand response across Europe
In addition to enabling price based demand response schemes as in Option 1, the objective
in this area is to remove the key barriers to incentive based demand response and flexibility
services in order to facilitate the market-driven deployment of these technologies to the
greatest practicable and economically viable extent. The new rules ensuring full market
access for independent aggregators will address the following:
-
-
-
Ensuring full non-discriminatory market access for consumers to all relevant
markets either individually or through third part aggregators.
Ensuring that each market participant contributes to the system costs according to
the costs and benefits (s)he induces to the system.
Removal of barriers at wholesale, balancing at capacity markets for aggregated
loads and for flexibility.
Option 3: Mandatory smart meter roll-out and full EU framework for incentive-based
demand response across Europe
The third option goes beyond the provision in Option 2. Instead of the right for consumers
to request a smart meter, it contains an obligation for a mandatory roll-out of smart meters
with the 10 recommended functionalities by 2025, for 80% of consumers in every Member
State. In addition, it contains a detailed framework for demand response that no longer
only defines principles for this framework but also defines favourable financial rules for
aggregators: The financial arrangements between aggregators and BRPs explicitly exclude
any financial transfers between aggregators and BRPs. The provisions on access of
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In both cases the requested systems must be able to ensure interoperability among the operators
responsible for metering and other participants in the electricity market and thus support the provision
of energy management and information services of benefit to the consumer.
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aggregated loads to wholesale, balancing and capacity markets remain unchanged from
Option 2.
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Comparison of the options
a. Effectiveness of options
In the context of this impact assessment two objectives are envisaged:
-
The accelerated deployment of fit-for-purpose smart metering systems that will
enable consumers to receive timely and accurate information on which they can
promptly act and accordingly adjust their consumption
–
in volume and time
–and
benefit from new energy services (e.g. demand response)
The uptake of demand response for consumer and system benefit
-
Smart Metering uptake
Assuming that no new EU intervention takes place, apart from the stronger enforcement
of existing legislation which is foreseen under
option 0,
and deployment plans go ahead
as they currently stand, smart meters will be installed only in those Member States where
their deployment is currently positively assessed, leading to a maximum EU penetration
rate of close to 72% by 2020. However, the systems to be rolled out will not necessarily
be interoperable, nor equipped in all cases, as recent data have shown
97
,
98
, with those
consumer benefitting functionalities (as listed in "Commission Recommendation on
preparations for the roll-out of smart metering systems") that support his participation in
novel energy services' programmes.
It is important to note here that increased functionality is directly associated to benefits,
but not to costs; it does not push up the overall cost of the deployment, given that it is
mainly software driven and its incremental cost is relatively low
99
. Issues related to
economies of scale and customisation may be more important in driving overall costs. So,
selecting fewer items from the set of common minimum functionalities does not
necessarily translate into less expensive systems. This makes a compelling case for
adhering from the start of the roll-out to the full set of the recommended functionalities
100
for the smart metering systems rolled-out.
Bearing in mind the intentions of the Member States regarding smart metering
functionalities, and for rolling out standardised interfaces to support the communication of
the metering infrastructure with devices and business platforms, in practice, much more
than 30% of EU customers by 2020 will be effectively denied the means
–
a fully functional
smart metering system - for getting involved in demand response schemes. Furthermore,
97
98
99
100
Commission Staff Working Document
"Cost-benefit analyses & state of play of smart metering
deployment in the EU-27"
(2014) Table 8
"
Status report based on a survey regarding Interoperability, Standards and Functionalities applied in
the large scale roll-out of smart metering in EU Member States"
(2015) Smart Grids Task Force Expert
Group 1
"Cost benefit analysis of smart metering systems in EU Member States"
(2015) ICCS-NTUA & AD
Mercados EMI ;
"Impact Assessment support study on downstream flexibility, demand response and
smart metering"
(2016) COWI
Report from the Commission
"Benchmarking smart metering deployment in the EU-27 with a focus on
electricity"
(2014)
http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=COM%3A2014%3A356%3AFIN;
supported with
data from the Commission Staff Working Document "Cost-benefit
analyses & state of play of smart
metering deployment in the EU-27"
(2014) .
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given that the meters installed will be in place for the next 15 years, which is their average
economic lifetime, the overall demand response potential will be significantly reduced up
to 2030.
For estimating the smart metering deployment for the alternative
Option 1
(smart meter
or its functional upgrade on request by the consumer) the following assumptions are made:
In countries with a reported large-scale roll-out of smart metering systems, the roll-
out occurs as planned, with the recommended functionalities not being though
throughout implemented. In all cases, customers will have access to dynamic tariffs
by 2020. This reflects greater customer and supplier awareness of the benefits of
smart meters;
-
In countries with either a limited (in terms of customer coverage or functionality)
roll-out or no planned roll-out, fully functional smart meters (or their upgrade) will
be made available to customers on demand.
The extent to which customers will choose the installation of a smart meter (or its
functional upgrade) will depend on a range of factors, including the proportion of overall
benefits that it could capture for them. Where a customer is faced with the full cost of smart
metering installation, extremely low take up is envisaged in the relevant Member States
based on current technology and its cost.
-
The analysis of national cost-benefit analyses for the roll-out of smart meters in those
countries not proceeding with a large scale roll-out has shown that customer related
benefits from smart metering systems are generally significantly lower than corresponding
per metering point costs. In two cases (Germany and Slovakia) the national CBAs have
concluded that a mandatory roll-out to all consumers would not be beneficial but only for
consumers above a certain consumption threshold:
In Germany a mandatory roll-out for all consumers with an annual consumption
above 6000kWh is proposed;
-
In Slovakia, the CBA considers that consumers with annual consumption above
4000kWh (covering 23% of metering points and 53% of Low Voltage
consumption) will overall benefit from an installation.
For the purpose of analysis, it is assumed that for all countries without a full purpose (in
terms of scale - nationwide, and function) roll-out of smart meters, the uptake of a smart
meter paid for by the consumer will be low in the short to medium term (up to 2020), but
may well increase significantly in the subsequent period to 2030 as the costs of meters,
communications and information technology fall, and the spread of appliances conducive
to price-based demand response rises. Therefore, the following estimates are made:
-
Take up of smart meters of around 10% of residential and small commercial
consumers by 2020 in Member States where no full purpose roll-out is planned;
-
Take up of smart meters of 40% of residential and small commercial consumers by
2030 in Member States where no full purpose roll-out is planned.
While no additional smart metering related measures are foreseen under
Option 2,
under
Option 3
a mandatory roll-out of smart meters to at least 80% of consumers in all Member
States is included, and this is to materialise irrespectively of the result of their national
assessments for the cost-effectiveness and feasibility of this deployment. Such a mandatory
roll-out will eventually lead to approximately 90% of all consumers having a fully
functional smart metering system installed by 2030. This reflects current experience with
smart metering roll-out where some installations for technical reasons may be too
expensive and some consumers refusing to have a smart meter installed because of privacy
concerns.
-
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In the light of these assumptions, the resulting estimates of smart meter roll-out and access
to dynamic tariffs under Option 1, 2 and 3 are set out below.
Table 2: Overview smart meter uptake
BAU = Option
Option 1
0
2016
Smart meter
35%
35%
2020
Smart meter
2030
Smart meter
71%
74%
72%
81%
Option 2
35%
72%
81%
Option 3
35%
72%
90%
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
Uptake of dynamic price contracts
In order to participate in price based demand response schemes, consumers not only have
to have a smart meter but also a dynamic electricity price contract. Under all options, it is
considered that the consumer must voluntarily opt in for such a contract. At this stage, only
estimates can be made on the number of consumer with a smart meter opting for dynamic
contracts, time of use contracts and static contracts. The following estimates have been
used for this analysis on the basis of various studies as well as pilot projects and initial
experience in the Nordic countries
101
:
101
The core estimated figures are in line with international trial studies and practical evidence, including:
-
The consumer survey of “Smart
Energy GB survey”,
which states that around 30% of the people
were either strongly or moderately in favour of switching to a ToU tariff;
-
The take-up rate of the Critical Peak Pricing ("CPP") tempo tariff in France that was slightly less
than 20% of the total consumers.
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Table 3: Uptake of dynamic and ToU price contracts of consumers with smart meters
BAU
Option 1
Option 2
Option 3
2016
ToU
10%
10%
10%
10%
Dynamic
0%
0%
0%
0%
2020
ToU
Dynamic
2030
ToU
Dynamic
18%
3%
26%
16%
18%
3%
26%
16%
18%
3%
26%
16%
18%
3%
26%
16%
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart metering"
(2016) COWI
The average uptake rate is identical for all options as for all options it is assumed that
dynamic tariffs are available for those consumers who wish to have one. In the case of
Member States not currently planning a large scale roll-out of smart metering systems and
for which optional take up applies under Option 1, a higher take up rate is assumed for the
calculation. This is done under the assumption that consumers actively opting for smart
meters are equally more likely to actively opt in for advanced price contracts. Hence the
take up rate for static ToU and Critical Peak Pricing (CPP) doubled in 2020 and 2030 for
customers with a smart meter (52% and 32% respectively in 2030).
Demand response uptake
The uptake of demand response was calculated on the basis of the smart meter roll-out and
uptake of dynamic price contracts as presented above taking into account the overall
demand response potential as presented in chapter 3.1.2.
Option 0 (BAU)
In case no additional measures are taken demand response will still develop across Europe.
The roll-out of smart meters will be carried out as planned and dynamic price contracts
will be available to consumers in Member States where mart meters are rolled out and
where the retail market is sufficiently competitive. Under the BAU, an increase of price
based demand response from 5.8 GW to 15.4 GW in 2030 is accepted.
It is important to note that the uptake of demand response depends heavily on the
appliances/loads residential consumers have in their possession:
-
For normal appliances, 4.9% of potential demand response is captured, while
-
For electric vehicles, heat pumps and smart appliances, 18.6% of potential demand
response is captured.
These figures are very sensitive to the take-up of new forms of price contracts. The
proportion of potential demand response for electric vehicles and heat pumps captured
ranges from around 13% for Member States not currently supporting a widespread roll-out
of smart metering systems to around 21% if it is planning a full scale roll-out.
110
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Incentive-based demand response will only develop very slowly as in the absence of a clear
enabling framework independent aggregation will remain limited and access of flexibility
to the markets limited. In total, under the BAU option demand response can increase from
21.4 GW in 2016 to 34.4 GW in 2030 or by 60%.
Option 1
In case only price based demand response is further enabled, the calculation shows that
total demand response would only increase compared to the BAU by approx. 2.5 GW by
2030 at an EU-wide level. This reflects the moderate additional uptake of smart meters
when each consumer has the right to have it installed.
Option 2
Incentive-based demand response is already represented in the wholesale energy markets
in half of the Member States. In policy Option 2, it is assumed that all Member States
having introduced some incentive based demand response already will reach a level of 5
per cent peak reduction in 2030, gradually increasing from today's level. The increased
level of demand response compared to Option 1 is due to adjustments in programme
requirements to better reflect the needs of demand side. This includes allowing aggregated
bids in the markets allowing aggregators enter the market as a service provider for industry
and large commercial consumers. There is also a standard process for settlements between
aggregators and suppliers to facilitate aggregation. Also, all Member States will introduce
incentive based demand response and the Member States not currently having incentive
based demand response, will reach a level of 3 per cent of peak load in 2030, the potential
gradually being introduced from 2021. The reasoning for take-up of demand response in
these Member States is the same, but they will start from a lower level than Member States
where demand response is already taking place.
Those measures will lead to an increase of incentive based demand response by approx.
15.6 GW or more than 80% compared to the BAU scenario. Under option 2 price based
demand response stays stable as no additional measures are introduced. Hence, total
demand response compared to the BAU scenario will increase by approx. 18GW or
52%
102
.
Option 3
In policy Option 3 it is assumed that all Member States having already introduced some
incentive based demand response will reach a level of 8 per cent peak reduction in 2030,
gradually increasing from today's level. Also, all Member States will introduce incentive-
based demand response and the Member States not currently having incentive based
demand response, will reach a level of 5 per cent of peak load in 2030, the potential
gradually being introduced from 2021. The increased level of demand response compared
to Option 2 is due to aggregators entering the market as a service provider under more
favourable conditions. Also, the prices for balancing reserves have increased due to
increased imbalances in the energy market. Those measures will lead to an increase of
incentive based demand response by approx. 20 GW or approximately double compared
to the BAU scenario.
102 In this Impact Assessment only the impact demand response is being quantified. Other forms of
consumer flexibility such as self-generation are being assessed under the RED II Impact assessment.
111
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Under this option it is assumed that price based demand response will remain unchanged.
While more consumers will have access to a smart meter it is unlikely that those additional
consumers who have not opted for a smart meter in the first place will request a dynamic
tariff and hence they will not participate in demand response schemes. Total demand
response compared to the BAU scenario will therefore increase by approx. 23GW or 66%
or by 4.7GW compared to Option 2.
Table 4: Overview of demand response (in GW/year) uptake for different options
BAU
Option 1
Option 2
Option 3
2016
Price-based
5.8
5.8
5.8
5.8
Incentive-
15.6
15.6
15.6
15.6
based
Total
21.4
21.4
21.4
21.4
2020
Price-based
Incentive-
based
Total
2030
Price-based
Incentive-
based
Total
6.4
16.3
22.7
15.4
19.0
34.4
6.9
16.3
23.3
17.9
19.0
36.8
6.9
20.3
27.2
17.9
34.6
52.4
6.9
21.4
28.4
17.9
39.3
57.1
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
b. Key economic impacts
Cost and benefits of smart metering
In this Section the cost-effectiveness and impact of smart metering is to be seen as part of
the bigger picture of delivering services to the consumer and enabling his participation in
price based demand response, and allowing him to offer his flexibility to the energy system,
and be rewarded for it.
Under
option 0,
the smart metering roll-out, following in most cases a positive CBA
undertaken by the Member States, is assumed to take place as planned. A complete listing
of
costs
and
benefits
associated with smart metering deployment in Member States can be
found in the Commission Benchmarking Report issued in 2014
103
. Available data there
103
(see Table 25 in) Report from the Commission
"Benchmarking smart metering deployment in the EU-
27 with a focus on electricity"
(2014)
http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=COM%3A2014%3A356%3AFIN;
112
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coming from the CBAs
104
of Member States that are proceeding with the roll-out, indicate,
despite their divergence, that the cost of installing a smart metering system for electricity
is on average close to EUR 225 per customer, while the benefit (per customer) is EUR 309
accompanied by energy savings in the order of 3% and up to 9.9% of peak load shifting.
The peak load shifting expectations vary greatly across the Member States; namely from
0.75% (UK) and 1% (Poland) to 9.9% in Ireland in the cluster of Member States that are
preparing a roll-out, and from 1.2% (Czech Republic) to 4.5% quoted in Lithuania in the
batch of Member States that are not presently proceeding with large-scale deployment.
These significant differences may be due to: (i) different experiences coming from locally
run pilot projects and/or hypotheses adopted in building the scenarios;
105
, and (ii), different
patterns considered in electricity consumption, e.g. presence of district heating, wide-
spread use of gas, etc.
On the
cost side,
meter costs (CAPEX and OPEX) are identified by the majority of Member
States as dominant followed by the capital and operational cost due to data communication.
In most countries (and relative to the electricity deployment arrangement of the country),
the smart metering investment and installation cost appears as an upfront cost for the
distribution system operator in the initial stage of the deployment; however, in most cases
they are later fully or partly passed to the final consumer through network tariffs.
Regarding
benefits,
data show that in a number of Member States
–
the Czech Republic,
Denmark, Estonia, France, Italy, Luxembourg and Romania
–
the distribution system
operator is the first/large direct
beneficiary
of the electricity smart metering, followed by
the consumer, and the energy supplier. The associated benefits have little to do with
demand response, and are related to administrative improvements in the areas of meter
reading, dis/re-connection, identification of system problems, fraud detection, as well as
increased customer services. Finally, other benefits can also be linked to smart metering
such as CO
2
emissions reduction due to first energy savings, as well as more efficient
electricity network operation (reduced technical and commercial losses); these result in
benefits accrued to the whole society.
It is important to note that to obtain full benefits, particularly consumption-related ones,
greater meter functionality is required. Yet, the CBAs show no direct link between cost
and functionality
106
. So, asking Member States to give under
Option 1
and
Option 2
the
entitlement to consumers to request a smart meter with full functionality, or the upgrade
of an existing one, should not pose any disproportionate costs on top of the meter unit cost.
However, the fact that smart meters will end up being rolled out on customer-per customer
104
105
106
and accompanying (i) Commission Staff Working Document
"Cost-benefit analyses & state of play of
smart metering deployment in the EU-27"
(2014), (ii) Commission Staff Working Document
"Country
fiches for electricity smart metering"
(2014)
idem
e.g. consumers' participation rate in demand response programmes (time-of-use pricing, etc.), different
consumer engagement strategies (e.g. indirect vs. direct feedback)
Report from the Commission
"Benchmarking smart metering deployment in the EU-27 with a focus on
electricity"
(2014)
; also confirmed in (i)
"
Cost benefit analysis of smart metering systems in EU Member
States"
(2015)
ICCS-NTUA & AD Mercados EMI
; and (ii)
"Steering the implementation of smart metering
solutions throughout Europe: Final Report"
(2014) FP7 project Meter-ON, p.9 and p.11;
http://www.meter-on.eu/file/2014/10/Meter-ON%20Final%20report-%20Oct%202014.pdf
113
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basis will not allow reaping in full system-wide benefits or benefits of scale and will lead
to higher per unit cost/benefit ratios.
In those countries where a large-scale roll-out is currently not foreseen and additional
meters are to be installed on customers' request, under
Option 1
and
Option 2,
the total
investment for installing additional meters could
–
as a first approximation - reach EUR 5
billion by 2030
107
for a penetration rate of 81% (compared to 74% in BAU). Half of these
costs for the installation of additional meters could potentially be offset by benefits (for
example lower costs/avoided costs of meter reading and operation, reduced commercial
losses
108
) other than those related to demand response
109
. As a result, the total cost by 2030
for the installation of these additional meters requested by consumers within the EU
–
under Option 1 and Option 2
–
could go down to EUR 2.47 billion; this corresponds to an
annual cost of EUR 215 million, for a period of 15 years (which is the average economic
lifetime of smart meters) considering a discount rate of 3.5%.
A similar calculation could also be undertaken for
Option 3
which will enforce the roll-
out of smart metering in all cases including those where deployment was found to be non-
beneficial according to the national economic assessment of long-term costs and benefits.
In this case, a mandatory roll-out throughout the EU could result in achieving ultimately a
penetration rate of 90% by 2030, and the additional smart metering installation costs could
rise beyond EUR 14 billion
110
. This figure represents the additional cost should a
mandatory smart meter roll-out is obligated throughout the EU. Half of these costs, as
argued earlier, could potentially be balanced by benefits linked to lower costs for meter
reading and operation and avoided commercial losses
111
. Consequently, the total additional
investment is halved, and the corresponding 'net' annual cost (for 15 years modelling
period, at 3.5% rate) is estimated at EUR 613 million (per year).
The tables below present the specific costs of additional meters installation, on consumer
request or obligated by legislation (Option 3), calculated per Member State, for the
alternative options considered.
107
108
109
110
111
The calculation is based on the projected smart metering penetration rate by 2030, and on an average
cost per metering point of EUR 279. This value is worked out from data of Member States' CBAs
–
both
positive and negative in their outcome - that were analysed under the "Study
on cost benefit analysis of
Smart Metering Systems in EU Member States-Final Report"
(2015) AF Mercados EMI and NTUA, and
presented on Table 8, p. 26 of the aforementioned report. This average value of EUR 279 per metering
point includes the smart meter costs, the information technology cost, communications costs and costs
for the installation of an In-Home Display (in the case of two Member States cost-benefit analyses).
Note
–
The accuracy of this calculation depends on the extent that a fixed cost (which is the total cost
for rolling-out to 80% of population) can be proportionately shared, and accordingly deployed to derive
the 'unit cost', which is then used to estimate, for any penetration rate, the cost of installation of smart
metering.
see Figure 4, page 34 of the "Study
on cost benefit analysis of Smart Metering Systems in EU Member
States-Final Report"
(2015) AF Mercados EMI and NTUA.
"Impact Assessment support Study on downstream flexibility, demand response and smart metering"
(2016) COWI.
Idem
idem
114
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Table 5: Overview of estimated costs for additional smart meter installation by 2030,
considering options 1 and 2
BAU=Option 0
Metering
points
5,700,000
5,975,000
4,000,000
2,500,000
450,000
5,700,000
3,280,000
709,000
3,300,000
35,000,000
47,900,000
7,000,000
4,063,366
2,200,000
36,700,000
1,089,109
1,600,000
260,000
260,000
7,600,000
16,500,000
6,500,000
9,000,000
2,625,000
1,000,000
27,768,258
5,200,000
32,940,000
Smart meter
penetration rate
by 2030
95%
0%
0%
0%
0%
0%
100%
100%
100%
95%
31%
80%
0%
100%
99%
95%
0%
95%
100%
100%
100%
0%
100%
23%
0%
100%
100%
100%
Option 1, Option 2
Additional meters
by 2030
(compared to BAU)
-
40%
40%
40%
40%
40%
-
-
-
-
10%
-
40%
-
-
-
40%
-
-
-
-
40%
-
17%
40%
-
-
-
Indicative cost
(EUR million)
by 2030
-
667
446
279
50
636
-
-
-
-
1,270
-
453
-
-
-
179
-
-
-
-
725
-
125
112
-
-
-
Country
Austria
Belgium
Bulgaria
Croatia
Cyprus
Czech Republic
Denmark
Estonia
Finland
France
Germany
Greece
Hungary
Ireland
Italy
Latvia
Lithuania
Luxembourg
Malta
Netherlands
Poland
Portugal
Romania
Slovakia
Slovenia
Spain
Sweden
UK
TOTAL
276,819,733
74%
7%
4,942
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
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Table 6: Overview of estimated costs for additional smart meter installation by 2030
considering Option 3
BAU=Option 0
Smart meter
penetration rate
by 2030
95%
0%
0%
0%
0%
0%
100%
100%
100%
95%
31%
80%
0%
100%
99%
95%
0%
95%
100%
100%
100%
0%
100%
23%
0%
100%
100%
100%
Option 3
Additional meters
by 2030
(compared to BAU)
-
80%
80%
80%
80%
80%
-
-
-
-
49%
-
80%
-
-
-
80%
-
-
-
-
80%
-
57%
80%
-
-
-
Indicative cost
(EUR million)
by 2030
-
1334
893
558
100
1272
-
-
-
-
6,615
-
907
-
-
-
357
-
-
-
-
1451
-
417
223
-
-
-
Country
Metering
points
5,700,000
5,975,000
4,000,000
2,500,000
450,000
5,700,000
3,280,000
709,000
3,300,000
35,000,000
47,900,000
7,000,000
4,063,366
2,200,000
36,700,000
1,089,109
1,600,000
260,000
260,000
7,600,000
16,500,000
6,500,000
9,000,000
2,625,000
1,000,000
27,768,258
5,200,000
32,940,000
Austria
Belgium
Bulgaria
Croatia
Cyprus
Czech Republic
Denmark
Estonia
Finland
France
Germany
Greece
Hungary
Ireland
Italy
Latvia
Lithuania
Luxembourg
Malta
Netherlands
Poland
Portugal
Romania
Slovakia
Slovenia
Spain
Sweden
UK
TOTAL
276,819,733
74%
16%
14,127
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
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Table 7: Overview of estimated 'net' yearly costs for additional smart meter
installation by 2030 considering all alternative options
BAU = Option Option 1, Option 2
Option 3
0
2030
Smart meter
74%
81%
90%
(penetration rate)
Additional 'net' cost
EUR 215
EUR 613
(considering 15 years,
million/year
million/year
at 3.5%)
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
Cost of demand response
To make demand response and its benefits possible, certain investments in the system are
necessary and operational costs will incur. For the activation costs of demand response
three classes are defined:
Table 8: Overview of cost components for demand response
Parameter
Cost component
Unit
Costs for loss of production, inconvenience costs,
Variable costs
EUR/kWh
storage losses
Annual fixed costs
Information costs, transaction costs, control costs EUR/kW
Installation of measurement-equipment, automatic
Investment costs
measurement for control, communication
EUR/kW
equipment
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
Variable costs
for demand response are the costs incurred at the consumer for offering
demand response. In case of load shifting these costs are considered to be zero since the
lost output can be produced later. However, it is possible that demand response causes
additional costs for inconvenience or efficiency losses due to partial load operations,
however these costs are expected to be minor and not possible to quantify and are therefore
not considered in this analysis.
The annual fixed costs
are incurred on a regular basis and are not related to the actual use
of demand response. Predominantly, these costs relate to administration and to incentivise
consumers for demand response. This analysis only focusses on the system costs, therefore
the annual fixed costs are assumed zero.
Investment costs
are incurred once the demand response potential is activated. Costs of
this type include
-
Investments in communication equipment both at the consumer side as in the grid.
This enables remote sending of instructions to the consumers who then can provide
demand response.
-
Investments in control equipment are needed to carry out load reductions
automatically. With control equipment it is possible to provide demand response
upon receipt of a signal.
-
Metering equipment is required to be able to verify that the load reduction is
achieved.
117
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At the moment there is relatively little information available of these investment costs for
demand response. Per consumer type, the following assumptions were made:
-
Industrial
consumers often already have equipment installed that can activate
demand response. On average, it is however assumed that a very small investment
is still required. According to available literature
112
, the investments are estimated
to be 1 EUR/kW.
-
To enable demand response for
residential
consumers, smart appliances must be
installed. This means the costs of appliances will be higher. Currently, most new
appliances already have an electronic controller which can make the appliance
“smart”. However, the appliance also has to be equipped with a communication
module, which will typically be either a power line communication (PLC) or a
wireless module (such as WLAN or ZigBee). It is assumed that due to mass
production of smart appliances in the future, the additional costs will be between
1.70 EUR and 3.30 EUR for all appliances that enable smart operation.
Furthermore, costs incur for the smart appliance to communicate with a central
gateway in a building. This can be integrated into a smart meter or can be offered
as a separate device. The gateway enables communication between the residential
consumer and an external load manager or aggregator. The link between the
appliances and the gateway (power line or wireless communication) does not
require the installation of additional wires. Small additional costs can be assumed
due to electricity consumption as a result of standby mode of smart appliances. This
is assumed to increase the electricity consumption of the appliance between 0.1%
and 2%.
-
For
commercial
consumers, the costs for demand response are not available in the
literature. Therefore, the costs are derived from the costs of demand response for
residential consumers. Because the electricity consumption of commercial
consumers is on average higher than the electricity consumption of residential
consumers, more load can be shifted. As a result, investments are lower per
kW/year. An assumption is made that the costs for commercial consumers will be
a factor 6 lower.
In the graph below, the costs of demand response are visualized per Option. As can be
seen, the costs are mostly related to the residential sector. This is a result of the higher price
per kW that is required to activate demand response.
112
"Quantifying the costs of demand response for industrial business"
(2013) Anna Gruber, Serafin von
Roon
118
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Graph 3: Costs of demand response in 2030
–
comparison of options
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
Benefits of demand response
Demand response is expected to decrease the peak demand and thereby the maximum
needed back-up capacity in the electricity market. The value of a decrease in back-up
capacity is expressed as a decrease in yearly CAPEX and fixed OPEX as a function of
installed capacity. Demand response also diminishes variable OPEX. When residual
electricity demand
113
is averaged (flattened) by demand response, less back-up power
needs to be generated by back-up units high in the merit order, and the variable costs of
electricity generation will be reduced. Together the decrease in fixed and variable costs
determine the estimated value of a demand response option in the electricity market.
Table 9: benefit of demand response for reduced back-up capacity in 2030
BAU
Option 1
Option 2
Option 3
Total demand response
34.4
36.8
52.4
57.1
potential 2030 (GW)
Total Value demand
response
(million
3517
3772
4588
4736
EUR/y)
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart metering"
(2016) COWI
In the distribution grids, demand response options can be deployed to reduce the peak, and
thereby the required capacity, in the distribution and transmission networks. These benefits
are reflected in a lower required investment in these grids. The benefits shown in the
column ‘distribution and transmission’ in the table below are estimated based on existing
literature on this topic in combination with the calculations of the overall possible peak
reduction as calculated for the system level. It is shown in modelling exercises that to a
large extent peak reduction at the system simultaneously reduces peaks in the distribution
113
Residual demand is the demand that remains after subtracting intermittent sources like solar and wind.
119
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grids. This makes this peak demand reduction a good starting point for estimating the
savings in the grids.
To estimate the savings per kW of peak capacity reduced, one needs to distinguish between
demand connected on the lower voltage and higher voltage grids. The savings on the higher
voltage are lower because only investments in transmission can be avoided. It is assumed
that industrial demand is on the higher voltage grids, while domestic and commercial
demand response is connected to the medium or lower voltage grids.
The average savings are used to calculate the savings that are made possible by the peak
reduction. The results are presented in the table below.
Table 10: Benefits of demand response in the distribution and transmission grid
BAU
Option 1
Option 2
Option 3
Total peak decrease
25.8
28.1
36.4
38.0
2030 (GW)
Total
benefit
demand response in
distribution
and
980
1068
1383
1444
transmission
grid
(million EUR/y)
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart metering"
(2016) COWI
Overall monetary cost and benefits for all Options
On the basis of the costs and benefits as presented above the net benefit of the different
options is calculated as summarised in the table below.
Table 11: Costs and benefits of Options for 2030 (in million EUR/year)
BAU
Option 1
Option 2
Option 3
Costs
82
303
322
328
Benefits
Network
Generation
Total
Net benefit
(compared to no
demand response)
Net benefit
(compared to
BAU)
980
3517
4497
1068
3772
4840
1383
4588
5971
1444
4736
6180
4415
4537
5649
5852
122
1234
1437
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart metering"
(2016) COWI
Using the approach described above, the net benefits of the alternative Options compared
to BAU amounts to about 120 MEUR/y for Option 1230 MEUR/y for Option 2 and around
1430 MEUR/y for Option 3. The net benefit includes the estimated savings in generation
and network capacity.
What is not included in the estimation of the benefits are the possible effects on system
costs, if the independent demand aggregators are free riders not baring any balancing
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responsibility and hence risk to activate the demand response in an inefficient way: for
example by bidding in the wholesale market but in the balancing markets where the price
might be higher. This could happen under Option 3 where no compensation between
aggregators and BRPs is foreseen, and hence the aggregators have no incentive to achieve
balance as early as possible in order to improve the overall efficiency.
What is equally not directly included in this calculation are reduced electricity prices in
the wholesale market due to demand response. However, those cost reductions are
indirectly included in the reduced generation costs.
The follow-on or indirect effects depend on how the savings are distributed among the
different actors. In competitive retail markets the major share of these savings will go into
lower electricity bills for the consumers. Lower electricity costs will increase welfare for
the residential consumers and increase competitiveness for industrial and commercial
consumers. However, in less competitive markets suppliers may profit from those price
reductions.
CO₂ emission reductions
Next to the monetary impact also CO₂ reductions can be achieved through a greater uptake
of demand response. Those impacts can add up to additional savings 1.5Mton/year by 2030
compared to the BAU scenario.
Table 12: Impact on CO₂
–
reduction in CO₂ emissions in Mton/y
BAU
Option 1
Option 2
Option 3
Reduction in CO₂ emissions
12.4
13.0
12.7
12.4
114
in Mton/y
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
c. Simplification and/or administrative impact for companies and
consumers
The measures proposed under Option 2 and 3 are designed to reduce market barriers for
new entrants and provide a stable framework for them under which they can operate in the
market. This is a necessity for new entrants who currently face great difficulties entering
the markets as incumbent suppliers do not allow them to engage with their customers. The
removal of such barriers is especially important for start-ups and SMEs who typically offer
innovative energy services such as demand response.
Equally for consumers all measures are designed to facilitate their access to innovative
products and services. Those measures should reduce the administrative impact for
consumers to get a fully functional smart meter and sign service contracts with third
parties. At the same time the measures also require Member States to clearly define roles
and responsibilities of aggregators which also increases confidence for consumers in their
services and contributes to consume protection.
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For options 2 and 3 the CO
2
benefits are less than for option 1, even if their total DR potential is higher.
This can be explained as follows: By applying DR, the peak demand will be diminished and less power
is generated by back-up units high in the merit order (e.g. gas plants). But at the same time some low
demand values will become higher after DR is implemented (we assume the total demand does not
change) and more power is generated by back-up units lower in the merit order (e.g. lignite plants).
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Moreover, thanks to a wider deployment of smart metering, under options 1, 2, and
particularly Option 3, the distribution system operators will be in a position to lighten and
improve some of their administrative processes linked to meter reading, billing,
dis/reconnection, switching, identification of system problems, commercial losses, while
at the same time offer increased customer services. Furthermore, a wider roll-out of smart
metering would allow TSOs to better calculate, and improve their processes, for
settlements and balancing penalties as the consumption figures can be based on real
consumption data and not only on profiles.
d. Impacts on public administrations
Regarding
smart metering,
there will be impacts on public administration, namely on the
Member States' competent authorities including the national regulators.
Those 17 Member States that roll-out smart meters will not be affected by provisions on
smart meters, under
all options,
apart from the obligation to comply with the
recommended functionalities, which they may need to transpose into national legislation.
Similarly, those two Member States that opted for partial roll-out are not expected to face
any major additional impacts from allowing additional consumers to request smart meters,
under
Option 1 and 2.
However, they will be impacted when enforcing a mandatory roll-
out under
Option 3
which will require substantial changes in their legislation as it currently
stands. The remaining Member States that currently do not plan to install smart metering
in their territory will need to establish legislation with technical and functional
requirements for the roll-out
–
under any of the options
–
and face some additional
administrative impact for re-evaluating their cost-benefit analyses.
Similarly, additional administrative impact may be created for the national regulatory
authorities (NRAs) for enforcing actions regarding the consumer entitlement to request a
fully functional smart meter. This includes assessing the costs to be borne by the consumer,
and overseeing the process of deployment. At the same time, improved consumer
engagement thanks to smart metering, would make it easier for NRAs to ensure proper
functioning of the national (retail) energy markets.
No additional impact on public administration is expected from facilitating incentive based
demand response as it is just a further specification/guidance on what is already an
obligation under EED.
e.
Trade-offs and synergies associated with each option with other foreseen
measures
Promoting a wider-scale deployment of smart metering with fit-for-purpose functionalities
is in line with the Commission's policy objectives namely to put the consumer at the core
of the EU's energy system, given that:
-
interoperable smart metering systems, equipped with the right functionalities, and
connectivity to support novel energy services, are considered essential under the
Energy Union Strategy for bringing tangible benefits to consumers and delivering
the "new deal";
-
through smart metering, consumers can clearly experience the internal energy
market working for them based on their preferences/choices, as it:
-
enables them to get accurate and frequent feedback on their energy
consumption;
-
minimize errors and delays in invoices or in switching;
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maximize their benefits from innovative solutions for consumption
optimization (e.g. via demand response) and from emerging technologies
(such as home automation); and ,
reduce the costs of the operation and maintenance of energy distribution
infrastructure (ultimately born by consumers through distribution tariffs).
Mandating the minimum functionalities for smart metering will clarify the need to go
beyond the capability of delivering just 'actual time of use' information currently
mentioned in the related provisions of the Energy Efficiency Directive.
-
Furthermore, the proposed smart metering functionality to collect meter data at intervals
at least equal to the market settlement frequency will support trading and the harmonisation
of balancing markets.
In addition to bringing tangible benefits to consumers, further developing demand response
is fully coherent with the objectives of other priorities in the field of energy policy as an
appropriate market framework for demand response:
-
is an enabler for integrating renewables efficiently into the electricity system. It
also contributes to render energy storage and self-consumption viable;
-
is a key factor for increasing energy efficiency with savings of final but mainly
primary energy;
-
is a key factor in promoting new products in balancing markets where new rules
are being elaborated under the Market Design Initiative to increase competition;
-
may help to reduce the need for creating capacity markets and will therefore be
considered under the rules for capacity markets to be proposed under the Market
Design Initiative;
-
will be needed to make efficient use of existing networks and thereby is at the core
of the proposal concerning new distribution tariff rules;
-
will likely trigger the deployment of smart homes and smart buildings technologies
while these will
vice-versa
increase the interest of residential and commercial
consumers in participating in demand response programmes. This deployment is
foreseen to be supported by measures to be adopted under the Ecodesign/Energy
Labelling Framework and by new approaches for smart buildings to be proposed
in the context of the review of the EPBD in 2016.
f. Uncertainty in the key findings and conclusions and how these might
affect the choice of the preferred option
The analysis on smart metering systems and especially demand response contains a lot of
uncertainty. For smart metering systems detailed national cost-benefit analyses have been
carried out in 2012. However, the underlying assumptions especially with regard to
technology costs that are significantly decreasing may change over time. Also the potential
benefits in terms of system and consumer benefits are subject to change depending on
technology development, the further integration of decentralised renewable energy
generation and upcoming offers for consumers taking part in demand response schemes.
Considering the above it is not unlikely that currently the costs for smart metering are over-
and the benefits under-estimated in some national cost-benefit analyses.
For incentive based demand response the uncertainty is even greater. Relatively good
estimates can be made about the theoretical potential of demand response (see chapter 2 of
this annex) where most of the theoretical potential lies with the residential sector.
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However, the technical and economic potential in the residential sector depends on a
number of external factors that are hard to quantify:
-
The willingness for residential consumers to engage in demand response. Pilot
projects have proven that consumers do engage in the market and adjust their
consumption if the incentives are right. These incentives are not always monetary
but can also be related to access to advanced information or energy managing tools.
However, it is impossible to transfer the results of pilots with engaged consumers
to the broad majority of consumers;
-
The uptake of heat pumps and electric vehicles that provide considerable shift-able
load will most probably determine if a huge number of residential consumers will
engage in demand response schemes. However, the uptake of those technologies is
yet uncertain;
-
Experiences from the Nordic market are not easily transferable to all EU markets
as the shifting potential in Finland is relatively high due to e.g. electric heating;
-
Experiences from the US market are equally not easily transferable to Europe as
the US market design is different. Furthermore wholesale peak prices are higher
and more frequent than in Europe. Hence, the economic value of demand response
in the US is higher than in the Europe.
The above indicates that the amount of the monetary benefits under the different options
is rather uncertain. The figures therefore rather indicate the magnitude of the potential
benefits under the different options.
As outlined earlier in this chapter there is also great uncertainty about the results calculated
for Option 3 in this impact assessment:
The analysis only covered the EU as a whole and did not look into national impacts
of a mandatory roll-out. It equally assumes the same cost of smart meters and their
roll-out across the EU. Therefore it cannot be excluded that in some Member States
the costs of a mandatory roll-out of smart meters exceeds its benefits as it was
concluded in some national cost-benefit assessments;
-
The analysis also did not quantify the potential system impact if independent
aggregators are exempted from financially covering the distortions they induce to
the system, e.g. not having any balancing responsibilities.
Therefore, the results of Option 3 are even more uncertain than under the other Options
and may very well lead to additional system costs and in some Member States to costs for
smart metering systems that are not covered by benefits for the system and/or the
consumer.
-
The uncertainty about the uptake of demand response does, however, not affect the
assessment of the preferred option. This option (Option 2) does not foresee any enforced
measures on the roll-out of smart meters or on the uptake of demand response. Instead, all
measures foreseen under this option are just enabling consumers to have access to the right
technologies and access to third party service providers. They also foresee to improve
access of flexibility to the markets. Under those framework conditions it will be the market
that will show to which degree demand response can play a role as a competitive service.
Therefore, Option 2 can be considered as a no regret option.
g. Preferred Option
Flexibility is considered to be instrumental for allowing more renewables into the
European electricity system without having to make large investments in conventional
back-up generation capacity. Therefore, introducing flexibility to the energy system by
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accelerating the uptake smart metering systems and of demand response are key elements
for realising the Energy Union's objectives.
All three Options are fully coherent with the objectives of the Energy Union and other EU
policies. The analysis has proven that all options are suited to accelerate the uptake of smart
metering systems and demand response as well as this uptake will lead to significant
system benefits and cost savings.
Option 1
supports the objective of increasing efficiency of the energy system by
introducing smart meters and dynamic pricing contracts. The Third Package included the
promotion of smart meters by requesting Member States to undertake a CBA of smart
meters and where the benefit-cost ratio is positive to roll-out smart meters. The realisation
of Option 1 means also in Member States where there is no general roll-out, relevant
consumers can ask for the smart meter and a dynamic price contract. It hence provides the
framework to allow all consumers to take advantage of the technological developments.
However, while better enabling price based demand is crucial for incentivising residential
consumers to benefit, it is not suited to realise the full benefits demand response can offer.
As such realising Option 1 will only lead to increase total demand response in Europe by
approximately 7% and lead to net benefits of approximately 120 MEUR/y by 2030
(compared to BAU).
In addition to the measures proposed under Option 1,
Option 2
is specifically addressing
incentive-based demand response. Article 15 of the Energy Efficiency Directive already
promotes demand flexibility and in that respect includes requirements for promotion of
demand response. The additional measures in Option 2 are based on the assessment that in
most Member States a complete legal framework for demand response is still missing. The
measures in Option 2 aim at providing this framework by creating fair market access for
independent aggregators and allow flexibility to be traded in organised markets. The
analysis has shown that those measures are indeed suited to increase the uptake of demand
response by approximately 52% which leads to system benefits of approximately 1230
MEUR/y by 2030 (compared to BAU).
Box X: Benefits and risks of dynamic electricity pricing contracts
The preferred option (Option 2) is to provide all consumers the possibility to voluntarily choose to sign up
to a dynamic electricity price contract and to participate in demand response schemes. All consumers will
have equally the right to keep their traditional electricity price contract.
Dynamic electricity prices reflect
–
to varying degrees
–
marginal generation costs and thus incentivise
consumers to change their consumption in response to price signals. This reduces peak demand and hence
reduces the price of electricity at the wholesale market. Those price reductions can be passed on to all
consumers. At the same time, suppliers can pass parts of their wholesale price risk on to those consumers
who are on dynamic contracts. Both aspects can explain why, according to the ACER/CEER monitoring
report 2015, on average existing dynamic electricity price offers in Europe are 5% cheaper than the average
offer.
While consumers on dynamic price contracts can realise additional benefits from shifting their consumption
to times of low wholesale prices they also risk to face higher bills in case they are consuming during peak
hours. Such a risk is deemed to be acceptable if taking this risk is the free choice of the consumer and if he
is informed accurately about the potential risks and benefits of dynamic prices before signing up to such a
contract.
Under
Option 3
a mandatory roll-out of smart meters to at least 80% of consumers in all
Member States is included. In addition it is assumed that under this option aggregators do
not have to cover the costs they induce to the system and hence do not pay any
compensation to BRPs. In terms of uptake of demand response (more than 100% compared
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to BAU) and overall system benefits (1430 MEUR/y by 2030) this is the most favourable
option. However, there are also other impacts that need to be considered in this respect:
-
This analysis did not take into account national differences in the costs/benefits of
smart meter roll-out but instead average figures were used. This approach does
hence not exclude the possibility that the overall economic impact of a mandatory
smart meter roll can be negative in some Member States as already suggested in
national cost-benefit analyses;
-
The exclusion of any compensation mechanism introduces a possibility of demand
aggregators being free riders in the markets and therefore creating inefficiencies.
This is not in line with the EU target model and generally not in line with creating
a level playing field for competition.
Option 2 is considered to be the preferred option, considering that
-
the modelling used for this Impact Assessment did not account for national
differences and did not calculate the impacts per Member State;
-
national cost-benefit analyses suggests that in some Member States mandatory roll-
out of smart meters yields negative net benefits; and that,
-
the overall banning of any financial obligations by independent aggregators may
lead to market distortions with unknown overall impacts.
Subsidiarity
The options envisage to give consumers the right to a smart meter with all functionalities
and access to dynamic electricity pricing contracts (Option 1) and in addition further
specify the roles and responsibilities of third parties offering demand response services
(Option 2). These actions promote the interests of consumers and ensure a high level of
consumer protection, and have their legal basis in Article 114 of the Treaty and Article 194
(2) TFEU. The policy measures considered under Option 3 can be based on the same
provisions.
Option1
-
The principle of subsidiarity is respected and EU action is justified as access to
smart metering systems is fundamental to improving the functioning of the internal
electricity market;
-
Ensuring universal consumer rights in the EU electricity markets includes the right
to actively engage in the market. This is only possible if technologies enabling
innovative energy services are available to all consumers across all Member States.
As stated earlier, for consumers to directly react to price signals on electricity markets, and
enjoy benefits coming from the provision of new energy services and products, they must
have access to both a fit-for-purpose smart metering system as well as an electricity supply
contract with dynamic prices linked to the spot market. However, today this is only a reality
in the Nordic Member States and Spain. In addition, under current national smart metering
rollout plans till 2020, more than 30% of EU consumers could be excluded from access to
such metering systems. The Commission's objective is to ensure that consumers have
access to all the prerequisites necessary to be rewarded for reacting to market signals.
This cannot be achieved sufficiently by Member States acting along. Therefore, it is herein
proposed to table provisions that will give each consumer, throughout the EU, the right to
request the installation of, or the upgrade to, a smart meter with all 10 functionalities
proposed in the Commission Recommendation on preparations for the roll-out of smart
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metering systems
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, while ensuring that consumers fairly contribute to associated costs.
Furthermore, it needs to be ensured that every consumer has the choice to select a dynamic
price contract linked to the prices at the spot market.
Action at EU level is relevant given that the current EU provisions, which leave the roll-
out of smart metering to the Member States' discretion based on the results of their cost-
benefit analysis, led to a fragmented, and even not necessarily functionally suitable in all
cases, deployment of smart metering.
Actions by Member States alone cannot ensure a harmonised level of consumer rights
(right to a smart meter that would enable customers access certain energy services) to the
extent to which under current national smart meter rollout plans for 2020, more than 30%
of EU consumers could be excluded from access to such metering systems. The right to a
smart meter with all the ten recommended functionalities is a precondition for consumers
to access energy services
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that require accurate and frequent billing information such as
demand response or electricity supply contract with dynamic prices linked to the spot
market.
The costs of rolling out smart meters - with all the benefits that this can bring for
consumers, network and energy companies, the energy system as well as society and the
environment more widely - will greatly increase if the economies of scale of the EU's
internal market are not properly leveraged. Regional differences have already risen with
respect to functionality and interoperability of the systems being rolled out, which may
result in set-ups that are not necessarily interoperable at national level, or within the EU.
This adds complexity and costs to those, be it for instance energy services/product
developers or aggregators, who would like to trade in different European countries and
optimise their business model. It points to the need to harmonise to a certain extent system
requirements and functionalities of smart electricity meters.
In the context of completing the EU's internal electricity market and making retail work
also for consumers, it is highly relevant to ensure at EU level a degree of consistency and
alignment, as well as gain momentum, in the deployment and use of smart metering
throughout Europe. Furthermore, ability to access novel energy services and products
should be indiscriminately offered to all EU citizens. This is what this action
–
giving the
right to request the installation of, or the upgrade to, a smart meter - is meant to deliver.
Such an action will eliminate ambiguities and strengthen the existing provisions, in order
to give certainty to those planning to invest, and ensure that smart metering roll-outs move
in the right direction, and regain EU added-value, by namely (i) safeguarding common
functionality and sharing best practices; (ii)ensuring coherence, interoperability, synergies,
and economies of scale, boosting competitiveness of European industry (both in
manufacturing and in energy services and product provision), and (iii) ultimately
delivering the right conditions for the internal market benefits to reach also consumers
across the EU.
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116
For example, provide readings directly to the customer and any third party designated by the consumer,
include advance tariff structures, time-of-use prices and remote tariff control, provide secure data
communications, etc. These also carry a host of other benefits such as improved consumer information,
enabling self-generation to be rewarded, and delivering flexibility to the system.
e.g. demand response, self-consumption, self-generation
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Option 2
EU intervention can be justified for several reasons, among them are:
-
To improve the proper functioning of the internal market and avoid the distortion
of competition in the field of retail energy services and hence fully enable demand
response
To empower consumers by enabling them to take advantage of the well-functioning
retail energy markets by easily accessing demand response services under
transparent and fair conditions.
-
Divergent national approaches related to the development of demand response services, or
the lack thereof, led to different national regulatory frameworks, raising barriers to entry
across borders to demand response aggregators. This initiative complies with the principle
of subsidiarity, as Member States on their own initiative would not be able to remove the
barriers that exist between national legislations to independent demand response service-
providers and to create a level playing field for them.
Each Member State individually would not be able to ensure the overall coherence of its
legislation with other Member States' legislations. This is why an initiative at EU level is
necessary. It will reduce costs for businesses as they will no longer have to face different
national regimes. It will create legal certainty for businesses which want to provide demand
response services in other Member States. Common rules are also crucial when e.g.
balancing markets will be opened for cross-border trade of flexibility.
Moreover, the present initiative will add value to other measures in the Market Design
Initiative. Other measures aimed at empowering customers, such as right to a smart meter
and to a dynamic ricing contract, will create new opportunities for European consumers
and energy service companies. These opportunities can only be exploited to their
maximum extent if they are completed by an initiative on addressing market barriers to
aggregators, so that they are able to provide customers with access to demand response
services.
Action from Member States alone is likely to result in different sets of rules, which may
undermine or create new obstacles to the proper functioning of the internal market and
create unequal levels of consumer rights in the EU. For example, a framework for demand
response for households is currently being developed in France, while in other Member
States there are currently no established rules for demand response aggregators targeting
household consumers. Common standards at EU level are therefore necessary to promote
efficient and competitive conditions in the retail energy sector for the benefit of EU
consumers and businesses.
An initiative at EU level would ensure that consumers in all Member States would benefit
from demand response services under harmonised conditions. It would also help removing
entry barriers for new service providers (aggregators), including cross-border, therefore
stimulating economies of scale and setting the basis for developing flexibility markets at
regional level. Such services have a cross-border development potential (e. g. Energy Pool
is already active in more than one EU Member States
–
France, UK).
Option 3
The same arguments to justify EU action as for Option 1 and 2 can be used for the policy
measures under Option 3. However, what concerns smart metering there could be doubts
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that a mandatory roll-out of smart meters with all recommended 10 functionalities
conforms to the principles of subsidiarity and proportionality. This is especially relevant
as Member States have already conducted national cost-benefit analyses on smart meter
roll-out. In 11 Member States those CBAs have unveiled that under current conditions the
costs of a roll-out exceed the benefits. In the Commission's analyses no evidence has been
found that those national CBAs or their underlying assumptions could be contested or that
economies of scale realised by a European roll-out would render the roll-out economically
viable. Hence, a mandatory roll-out would effectively impose undue costs on those
Member States where the CBAs have been negative. However, the underlying assumptions
of those CBAs are likely to change over time with technology cost expected to decrease
which may lead to viable roll-outs in the near future.
The principle of proportionality may equally be contested for strict harmonisation of the
legislative framework for independent aggregators and demand response. A certain degree
of freedom for Member States to design the framework for demand response according to
the national design of the markets may indeed have a similar impact than fully harmonised
rules.
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Stakeholders' opinions
Outcome of the public consultation
Result of public consultation Energy Market Design
The consultation on the market design contained one question on demand response:
"Where do you see the main obstacles that should be tackled to kick-start demand
response (e.g. insufficient flexible prices, (regulatory) barriers for aggregators /
customers, lack of access to smart home technologies, no obligation to offer the
possibility for end customers to participate in the balancing market through a demand
response scheme, etc.)?"
Many stakeholders identified a lack of dynamic pricing (more flexible consumer prices,
reflecting the actual supply and demand of electricity) as one of the main obstacles to kick-
starting demand side response, along with the distortion of retail prices by taxes/levies and
price regulation. Other factors include market rules that discriminate consumers or
aggregators who want to offer demand response, network tariff structures that are not
adapted to demand response and the slow roll-out of smart metering. Some stakeholders
underline that demand response should be purely market driven, where the potential is
greater for industrial customers than for residential customers. Many replies point at
specific regulatory barriers to demand response, primarily with regards to the lack of a
standardised and harmonised framework for demand response (e.g. operation and
settlement).
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In total, eleven Member States responded to the question with ten putting specific emphasis
on the need for effective price signals that reflect price developments at the wholesale
market and incentivise consumers to adjust their consumption. In addition, seven Member
States highlighted the need for market rules that allow demand response to participate in
wholesale, balancing and capacity markets on equal footing with generation. Also
environmental NGOs have been widely supportive of demand response stressing the need
for demand side measures to efficiently integrate renewables to the system. Therefore, they
call for opening the markets for flexibility. Some organisations call for intensified R&D in
the area and/or support schemes while one organisation also calls for targets for demand
response. However, Member States and other stakeholders see demand response as a
market driven service for which no specific support but fair market conditions is needed.
More detail on the opinion of main stakeholders is presented under the individual
stakeholder organisations.
Result on public consultation on the Review of Directive 2012/27/EU on Energy Efficiency
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IEA "Re-powering
markets"
(2016) suggests:
Reform of retail pricing is urgently needed to better reflect
the underlying cost level and structure. Current tariff and taxation structures which do not vary with
time can lead to inefficiencies. Investments in distributed resources are not always cost-effective as bill
savings do not properly reflect the avoided costs to the electricity system. The significant difference in
speed between installing solar PV and small-scale storage and building large-scale power infrastructure
can exacerbate this problem."
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The consultation addressed a number of questions on metering with one specifically
addressing electricity smart meters and hence is immediately relevant to this impact
assessment:
"Do you think that
-
-
the EED requirements regarding smart metering systems for electricity and
natural gas and consumption feedback and
the common minimum functionalities, for example to provide readings directly to
the customer or to update readings frequently, recommended by the Commission
together provide a sufficient level of harmonisation at EU level? "
37% shared the view that the EED requirements regarding smart metering systems for
electricity and natural gas and consumption feedback and that the common minimum
functionalities recommended by the Commission together provide a sufficient level of
harmonisation at EU level. 36% had no view, and 27% did not think that these provisions
would provide a sufficient level of harmonisation.
Several participants explained that smart meters would have to provide more useful
information to consumers, potentially in 15 minute intervals, or even in real time. Some
also suggested that consumers could receive a notification once every three months with
an overview on whether they are saving energy and hence money, or whether they are
consuming more than would be expected. Yet others noted that the above factors largely
depend on market conditions, and on how providers interact with customers. In general,
many participants shared the view that EU standards should only apply to minimum ones,
as any additional standards could significantly increase the enterprise's complexity.
Additionally, several stated that harmonisation must also take into account acceptance by
citizens. Finally, some also cited evidence that calls the effectiveness of smart meters in
general into question.
Of those 27% who think that the EED requirements regarding smart metering systems for
electricity and natural gas and consumption feedback and the common minimum
functionalities, recommended by the Commission together do not provide a sufficient level
of harmonisation at EU level, 48% share the view that common minimum functionalities
should be the basis for further harmonisation. 31% had no view, and 21% did not thing
that common minimum functionalities should be the basis for further harmonisation. Some
called for additional minimum functional standards to the current ones, for example,
monthly or three monthly electronic feedback for consumers on how much energy they are
savings. Some participants also argued that the interface of smart meters should be
standardised, to facilitate their use. Yet others voiced a shared perception that standards
across the EU would be overly determined by utilities.
More detail on the opinion of main stakeholders is presented under the individual
stakeholder organisations. While among all respondents the views on the need of additional
EU actions was balanced, the opinion of national ministries signal that the majority of
Member States believe that the existing provisions are sufficient. Out of 14 replies from
Member States only 2 were of the opinion that more harmonisation on EU level would be
good to ensure that consumers get the full benefit out of smart meters while 9 consider that
the level of harmonisation provided by existing legislation is sufficient and 3 do not state
a clear opinion.
European Institutions
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Council of the European Union, messages from the presidency on electricity market design
and regional cooperation, April 28, 2016, 7876/1/16 REV1
In addition to stakeholders also European Institutions in response to the communications
"Launching the public consultation process on new energy market design"
(SWD(2015)
142 final) as well as
"Delivering a new deal for consumers"
(SWD(2015) 141 final) clearly
highlighting the need for smart metering systems, demand response and the importance of
allowing new market participants (aggregators) to compete in the markets.
European Parliament, Committee on Industry, Research and Energy, Rapporteur: Werner
Langen, DRAFT REPORT on ‘Towards a New Energy Market Design’, 27.1.2016,
2015/2322(INI)
"The future electricity retail markets should ensure access to new market players (such as
aggregators and ESCO’s) on an equal footing and facilitate introduction of innovative
technologies, products and services in order to stimulate competition and growth. It is
important to promote further reduction of energy consumption in the EU and inform and
empower consumers, households as well as industries, as regards possibilities to
participate actively in the energy market and
respond to price signals,
control their energy
consumption and
participate in cost-effective demand response solutions.
In this regard,
cost efficient installation of smart meters and relevant data systems are essential.
Barriers that hamper the delivery of demand response services should be removed."
European Parliament, Committee on Industry, Research and Energy, Rapporteur: Theresa
Griffin, REPORT on delivering a new deal for energy consumers, 28.4.2016, A8-
0161/2016
"5. Recalls that the ultimate goal should be an economy based on 100%
renewables, which can only be achieved through reducing our energy
consumption, making full use of the ‘energy efficiency first / first fuel’ principle
and
prioritising energy savings and demand side measures over the supply side
in order to meet our climate goals…"
-
"6.b empower citizens to produce, consume, store or trade their own renewable
energy either individually or collectively, to take energy-saving measures, to
become active participants in the energy market through consumer choice,
and to
allow them the possibility of safely and confidently participating in demand
response;"
-
"33. Stresses that to incentivise demand response, energy prices must vary between
peak and off-peak periods, and therefore
supports the development of dynamic
pricing on an opt-in basis,
subject to a thorough assessment of its impacts on all
consumers; stresses the need to
deploy technologies that give price signals which
reward flexible consumption,
thus making consumers more responsive; … reminds
the Commission that when drafting the upcoming legislative proposals it should be
guaranteed that the introduction of dynamic pricing is matched by increased
information to consumers;
-
"37. Emphasises that consumers should have a free choice of aggregators and
energy service companies (ESCOs) independent from suppliers";
Committee of the Regions, Opinion of the European Committee of the Regions
–
Delivering
a New Deal for Energy Consumers, 8 April 2016, ENVE VI -/009
-
-
"3. notes the extremely high number of services and technical solutions that exist
or are currently being developed in the fields of management and demand
132
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-
-
-
response, as well as in the management of decentralised production. The European
Union must ensure that priority is given to encouraging and supporting the
development of these tools, assessing their value and impact, whether economic,
social, environmental or in terms of energy, and monitoring their usage to make
sure that energy is safe, easy and affordable";
"24. observes that a level playing field should be created for all future players who
generate and supply energy and/or provide new services, in order to enable, for
example, grid flexibility and integration of energy produced by "prosumers"
(including aggregators)";
"42. reiterates its call to speed-up the development of smart systems at both grid
and producer/consumer level, to optimise the system as a whole, as well as to
introduce smart meters, which are essential to the efficient management of
demand with the active involvement of the consumer";
"43. calls for the adoption of a strict framework at European level on the
deployment of
smart meters and their range of uses and features,
whilst recalling
that the aim is to streamline and reduce consumption. In this regard, the Committee
calls for all new technology options to be evaluated prior to adoption, if they are
to be introduced as standard, with regard to their potential energy, economic,
social and environmental impact";
Selected Stakeholder's views
Florence Forum of electricity regulation
–
Conclusions of 31 meeting on June 13, 2016
The Forum recognises that the development of a holistic EU framework is key to unlocking
the potential of demand response and to enabling it to provide flexibility to the system. It
notes the large convergence of views among stakeholders on how to approach the
regulation of demand response, including:
-
-
-
-
-
The nееd to engage consumers;
The need to remove existing barriers to market access, including to third party
aggregators;
The need to make available dynamic market-based pricing;
The importance of both implicit and explicit demand response; and,
The need to put in place the required technology.
Regulators (ACER/CEER)
The Agency for the Cooperation of Energy Regulators (ACER) and the Council of the
European Energy Regulators (CEER) both welcomed the Commission's energy market
design consultation paper of July 2015, and in particular the reinforced steer towards cross-
border and market-based solutions, and noted its
"alignment
in thinking"
with their
133
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Bridge to 2025
proposals and sharing of
"the common aim of
establishing liquid,
competitive and integrated energy markets that work for consumers”
118
.
They consider that
"a well-functioning market is characterised by innovation and a
range of products offered to consumers",
which
"can be a sign of healthy competition and
innovation in the market".
Key features of this new consumer-centric energy market model
advocated by the regulators
119
rely on
"near
real time frequency of smart metering data
for all",
and
"demand
response through flexible consumption".
The latter translates into
"availability
of time-of-use/hourly metering and different pricing schemes offers from
suppliers and availability of aggregation services from third-party companies".
To assist
realising this, CEER amongst other works towards ensuring that "most
customers have a
minimum knowledge of the most relevant features for engaging and trusting the market",
access to
"empowerment tools"
and
"a minimum level of engagement",
as well as that the
"regulatory framework allows and incentivises the availability of a range of offers"
120
.
CEER when discussing
121
implicit, or price-based demand response,
it states that
"without
smart meters (and optionally in addition other facilitators such as smart
appliances)"
and in the absence of
dynamic pricing contracts,
there are
"limited
possibilities for retailers to value demand side flexibility in their portfolio optimisation".
CEER further notes that "access
to contracts that directly link the energy component to
wholesale markets with a possible granularity down to hourly-based prices create a bridge
between wholesale and retail markets, incentivising consumers to exploit opportunities
when prices are low and to adjust consumption when prices are high".
Furthermore, CEER affirms that
"the
availability of smart metering equipment and
systems
which allow time-of-use meter readings
is a pre-requisite for consumers
to be
able
to opt into implicit demand response
schemes. Smart meters may also enable explicit
demand response services through a dedicated standard interface, either as mandatory
equipment or an option"
122
. But for smart meters to be able to deliver this service, they
need to be fit-for-purpose, and therefore equipped with the right functionalities. CEER
notes that
"there is a
consistency and convergence
between the work of European Energy
Regulators and the European Commission regarding smart meter functionalities, in
particular those which benefit consumers".
At the same time, however, CEER does not
consider these elements sufficient for providing the necessary level of harmonisation
across the EU,
"the issue being that Member States do not apply them". Consequently,
118
119
120
121
ACER/CEER common press release
"Energy Regulators (ACER/CEER) welcome the market-based
solutions and cross-border
focus of the European Commission’s energy market design",
15.07.2015;
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/PRESS_RELEASES/201
5/PR-15-07_Joint-CEER-ACER%20PR%20%20-EnergyMarketDesignConsultation_FINAL.pdf
CEER
presentation
at
the
12th
EU-US
Roundtable,
03.05.2016;
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_INTERNATIONAL/EU-
US%20Roundtable/12th_EU-US_Roundtable/12th%20EU-US%20RT_S4-
International_deSuzzoni.pdf
idem
CEER
discussion
paper
"Scoping
of
flexible
response",
3
May
2016;
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Electrici
ty/2016/C16-FTF-08-04_Scoping_FR-Discussion_paper_3-May-2016.pdf
CEER
"Position
paper
on
well-functioning
retail
energy
markets",
,
14
October
2015;
122
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Custom
ers/Tab5/C15-SC-36-03_V19_Well-functioning_retail_markets.pdf
134
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CEER are
in favour of using the "minimum functionalities as a basis for further
harmonisation"
123
.
TSOs (ENTSO-E)
ENTSO-E considers that
"the development of demand-side response (DSR) should ensure
that
demand elasticity is adequately reflected in short-term price building and long-term
investment incentives.
DSR can deliver different types of products and participate in the
associated markets with large socio-economic welfare gains"
124
. Furthermore, ENTSO-E
notes that
"the organisation of, and timely access to, metering and settlement data which
will be made available by smart meters is essential for facilitating the uptake of DSR"
125
.
Elaborating on that, ENTSO-E states that the full potential can be unleashed if the
following requirements
126
are satisfied, namely:
(i)"price
signals
need to reveal the value of flexibility"
for the electricity system;
(ii)"efficient
use of DSR is based on an economic choice between the value of consumption
and the market value of electricity. This choice arises when the
consumer is exposed to
variable prices or
if the consumer
can sell his flexibility on the market,
possibly with the
help of an aggregator".
(iii)
"access
to price information, consumption awareness
and DSR activation require
strong consumer involvement, which can be facilitated with
automation
or by delegating
the DSR process from the consumer to a company";
(iv)
"regulatory
barriers,
when present,
need to be removed
to unlock full DSR potential,
including barriers related to the
relationship between independent aggregators and
suppliers.
Any evolution must preserve the efficiency and well-functioning of markets and
their design components, such as the pivotal role of balance responsible parties, their
information needs and balancing incentives. From a TSO perspective, the choice of the
market model results from a
trade-off between the imperatives not to increase residual
system imbalance and to facilitate the development of additional resources";
(v)"DSR
should develop itself based on viable business cases.
Subsidies should remain
limited and clearly identified";
123
124
125
126
CEER Response to European Commission Public Consultation on the Review of the Energy
Efficiency Directive, 29 January 2016;
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Custom
ers/Tab6/C16-CRM-96-04_EC_PC_EED_Response_290116.pdf
ENTSO-E policy paper "Market
design for demand response",
November 2015;
https://www.entsoe.eu/Documents/Publications/Position%20papers%20and%20reports/entsoe_pp_dsr
_web.pdf
ENTSO-E position paper "Towards
smarter grids: Developing TSO and DSO roles and interactions for
the
benefit
of
consumers",
March
2015;
https://www.entsoe.eu/Documents/Publications/Position%20papers%20and%20reports/150303_ENTS
O-E_Position_Paper_TSO-DSO_interaction.pdf
ENTSO-E policy paper "Market
design for demand response",
November 2015;
https://www.entsoe.eu/Documents/Publications/Position%20papers%20and%20reports/entsoe_pp_dsr
_web.pdf
135
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(vi)"Communication
and control technologies
need to enable DSR for small consumers
and provide guarantees on their reliability".
ENTSO-E also clarifies that
"to enable dynamic pricing, settlements must be based on at
least hourly metering values",
which means that
"Member States must phase out static
consumption profiles, and introduce time-of-stamped (at least hourly) smart meter
readings for consumers"
127
.
DSOs (CEDEC, EDSO for Smart Grids, EURELECTRIC, GEODE)
The four DSOs associations appreciate the contribution of demand response towards
achieving EU energy objectives, and recognise the need for active customers participating
in the markets. They state that
128
"with the growing uptake of smart grids and distributed
energy connected to Europe’s distribution grids, DSOs are successfully embracing the
‘digitalisation’ transformation",
and are
in favour
of "the procurement of flexibility
services in an open market context
where everyone, including end users, is welcome to
take part.”
They have also affirmed in different fora their conviction on the key role that
smart metering plays in delivering that function and the accompanying benefits, by
providing accurate and secure data on energy consumption, while enabling customers to
make smart choices helping them to also save money and energy.
CEDEC
CEDEC considers that
129
"in order to implement effective demand-response programmes,
signals about demand and supply need to be received, managed and communicated to the
relevant parties. For this, the development of smart distribution grids is indispensable".
Moreover,
"for the development of smart grids, cost-reflective regulatory frameworks need
to be in place… " giving the right incentives, that should amongst others, "allow for time-
differentiated prices, which will
give price signals to consumers to shift their
consumption
from peak to off-peak times"
130
. Such settings are more complex and in fact
"only
possible with a smart meter"
131
.
EDSO for Smart Grids
127
128
129
130
131
ENTSO-E
"Recommendations to the regulatory framework on retail and wholesale markets";
Input to
EC Market Design Package; 10 June 2016.
DSOs Associations' joint event
"Innovative DSOs are needed in a Decentralised Energy System",
12.04.2016,
http://www.geode-
eu.org/uploads/GEODE%20Germany/Stellungnahme/2016/0411%20FINAL%20Joint%20PR%20-
%20Innovative%20DSOs%20in%20a%20decentralised%20energy%20system.pdf
CEDEC position "
on EC Communication - Delivering the internal electricity market and making the
most of public Intervention",
December 2013;
http://www.cedec.com/files/default/cedec-position-ec-
guidance-package-final.pdf
CEDEC publication "Smart
grids for smart markets",
2014;
http://www.cedec.com/files/default/cedec_smart_grids_position_paper-2.pdf
CEDEC publication "Distribution
grid tariff structures for smart grids and smart markets",
2014;
http://www.cedec.com/files/default/cedec%20leaflet%20grid%20tariffs-final-140403-1.pdf
136
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EDSO considers that DSOs are at the core of the energy transformation and have
"the
potential to empower consumers
to take a more active part in the energy system, for
example,
by rolling-out smart meters"
132
. Furthermore, EDSO argues that
"engaging
consumers will require appropriate incentives and technologies",
as well as
"clear price
signals", for flexibility markets to develop and demand response to deliver its full
benefits"
133
.
EDSO notes that incentives for
"dynamic
tariffs or incentive based demand
response"
should be set up
"in order for the consumer to make savings by offering
controllable loads to network operators".
It also advocates that a
"revision of grid tariffs
with time-dependent and site-dependent components or incentive based demand response,
is an essential step towards realising the benefits, as well as for passing on the costs of
flexibility"
134
.
Furthermore, EDSO states that
"DSOs could make the most of their grid provided that they
are allowed to use system flexibility services
"135
. Moreover,
"increasing
flexibility
in the
electricity market (when technically and economically appropriate) would result in a
number of benefits for DSOs, consumers (all grid users) and society as a whole".
However,
according to EDSO
"this implies that
distribution networks are planned differently,
incorporating new risk margins and uncertainty, are not only managed as they used to be,
but rather as networks with enhanced observability, controllability and interactions with
market stakeholders".
Regarding smart metering functionalities, EDSO claims
136
that the
"EED requirements
and the EC recommendation" on common minimum functionalities
"have been
useful
in assisting the industry identify the most relevant functionalities for smart meters.
Now
that most national deployments are underway or near launch,
there is no need for further
action from the European Commission".
Furthermore, it notes that
"proposing to further
harmonise
smart meter systems at this time, beyond the existing EC’s recommendations
on minimum smart metering functionalities, could further delay smart meter deployment
and thus consumers’ access to detailed and accurate information on their energy
consumption".
EURELECTRIC
Eurelectric acknowledges that
"demand response will be one of the building blocks of
future wholesale and retail markets",
and
"the development of innovative demand response
services will empower customers, giving them more choice and more control over their
132
133
134
135
136
EDSO report "Data
Management: The role of Distribution System Operators in managing data",
June
2014;
http://www.edsoforsmartgrids.eu/wp-content/uploads/public/EDSO-views-on-Data-
Management-June-2014.pdf
EDSO report "Flexibility:
The role of DSOs in tomorrow’s electricity market",
May 2014;
http://www.edsoforsmartgrids.eu/wp-content/uploads/public/EDSO-views-on-Flexibility-FINAL-
May-5th-2014.pdf
idem
System flexibility services: any service delivered by a market party and procured by DSOs in order to
maximise the security of supply and the quality of service in the most efficient way
–
Reference: EDSO
report "
Flexibility: The role of DSOs in tomorrow’s electricity market",
May 2014.
EDSO response to the Consultation on the Review of Energy Efficiency Directive, January 2016;
http://www.edsoforsmartgrids.eu/wp-content/uploads/160129_Public-consultation-Energy-Efficiency-
Review_final_EDSO.pdf
137
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electricity consumption. Phasing out regulated retail prices and
rolling out smart meters
continue to be
key prerequisites
to advance demand response further"
137
. As Eurelectric
explains
138
it is
"fit-for-purpose
smart meters"
that are needed and are "... a key tool to
empower consumers".
And
"…without prejudice to smart meter rollouts which are already
ongoing, it would be
important to guarantee that all smart meters across the EU had a
minimum agreed common set of functionalities
to make sure that they contribute to
consumer empowerment and efficient retail markets. Basic common functionalities would
include, for example, the possibility of performing remote operations, the capability to
provide actual, close to real-time meter readings to consumers,
or the possibility to
support advanced tariff schemes"
139
. Furthermore, Eurelectric supports the position that
"smart
meters with a reading interval corresponding to the settlement time period are a
technical prerequisite
for participation of users (with aggregated flexibility units) in
balancing markets"
140
.
To untap the full demand response potential, Eurelectric recommends
141
:
(i) "ensuring
that the
demand response value is market-based
in order to avoid any extra
costs to the system, customers and other actors";
(ii)
"implementing
adequate communication
between third party aggregators and balance
Responsible Parties (BRPs)/suppliers to ensure that demand response can take place
effectively";
(iii)
"ensuring that BRPs/suppliers are compensated for the energy they inject and that is
re-routed by third party aggregators",
and
"to this end, third party demand response
aggregators and suppliers agree on the
rules of compensation.
Changes in market rules
and settlement adjustments could also be implemented. In addition, a
clear balance
responsibility of third party aggregators
is needed";
(iv)
"ensuring that, on a commercial basis, BRPs/suppliers are able to
renegotiate supply
contracts
to take into account the indirect effects of demand response (e.g.
rebound
effects)
and consequent impacts on sourcing costs";
and
(v)
"facilitating demand response aggregation at distribution network level through
information exchange between DSOs, TSOs and aggregators, for example
using a system
that reflects network availability".
137
138
139
140
141
Eurelectric report "Designing
fair and equitable market rules for demand response aggregation",
March 2015;
http://www.eurelectric.org/media/169872/0310_missing_links_paper_final_ml-2015-
030-0155-01-e.pdf
Eurelectric report "The
power sector goes digital - Next generation data management for energy
consumers",
May 2016;
http://www.eurelectric.org/media/278067/joint_retail_dso_data_report_final_11may_as-2016-030-
0258-01-e.pdf
idem
Eurelectric report "Flexibility
and Aggregation
–
requirements for their interaction in the market",
January 2014;
http://www.eurelectric.org/media/115877/tf_bal-agr_report_final_je_as-2014-030-0026-
01-e.pdf
Eurelectric report "Designing
fair and equitable market rules for demand response aggregation",
March 2015;
http://www.eurelectric.org/media/169872/0310_missing_links_paper_final_ml-2015-
030-0155-01-e.pdf
138
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GEODE
The association for the local energy distributors GEODE identifies the non-wide
deployment of smart metering as one of the main barriers for demand response taking off,
stating that there is
"…no
demand response and actual consumption data without smart
meters
- which are still being rolled-out in many Member States"
142
. Furthermore, it argues
that
"…demand side flexibility
aggregators should have access to balancing markets on
a level playing field with other parties",
and that
"…the
end customer should participate
[in demand response schemes]
on a voluntary basis only".
Moreover, even though GEODE recognises the need, as stated in different fora, to ensure
that smart metering systems with the right functionalities are rolled out to support demand
response, it cautions on the making a set of functionalities binding without at least
foreseeing a transition period for implementation. Following a survey that the association
undertook among its members on the use of the common minimum functionalities for
smart metering systems recommended by the Commission, it acclaimed
143
that
"… in those
countries where the roll-out has just started or is still in a planning phase, almost all
requirements as recommended by the European Commission are implemented".
However
it continues,
"…if the European Commission is considering
making binding the
recommendations on smart meter functionalities
[…]
these should apply for the next
generation of meters to be rolled-out.
At least, a
sufficient transitional period should be
provided
which is as long as the expected lifetime of the smart metering systems already
installed respectively smart metering systems which are going to be installed in the next
years - tenders are currently running or the roll-outs have recently started with the
objective to reach the 2020 target of 80%. Otherwise it would
–
once again - require huge
investments to be made by DSOs for replacing existing meters."
Suppliers (Eurelectric)
Suppliers state that
"while demand response has been and could continue to be deployed
by suppliers without
smart metering
or connected appliances, these technologies
will
facilitate more advanced dynamic pricing and new demand response services"
144
. They
recognise the benefits that the advent of smart metering, smart devices and overall
digitisation of the energy sector will bring in this respect, and how it will change their
interaction with consumers taking into a new level
"changing their traditional business
142
143
144
GEODE Comments to the European Parliament Draft
Report on “Delivering
a New Deal for Energy
Consumers",
http://www.geode-
eu.org/uploads/GEODE%20Germany/DOCUMENTS%202016/GEODE%20Final%20Comments%20
-%20EP%20Draft%20Report%20New%20Deal.pdf
GEODE Position paper sent to EC services, dated 20/04/2016, entitled: "GEODE Survey
–
to assess
whether EC common minimum functional requirements for smart metering systems for electricity - EC
Recommendation of 9 March 2012 on preparations for the roll-out of smart metering systems
(2012/148/EU) are implemented by GEODE member companies"
Eurelectric brochure "Everything
you always wanted to know about Demand Response",
2015;
http://www.eurelectric.org/media/176935/demand-response-brochure-11-05-final-lr-2015-2501-0002-
01-e.pdf
139
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models, based on pure delivery of kilowatt-hours towards
becoming full service
providers"
145
. Suppliers will
"have access to new data sources and tools to communicate
with their customers and better understand their needs".
Furthermore, they
"…will (also)
be able to provide consumers with information on - and prediction of - their energy usage
and consumption patterns, even breaking it down into
close to real-time
information…through
extra devices",
and enable the delivery to them of
"more
personalised offers and services
by market players".
This includes the proposition of
"innovative
demand response or time of use tariffs
which
contribute to the efficient
operation of the energy system whilst being financially attractive, transparent and
guaranteeing a given level of comfort to consumers
through remote steering of connected
appliances."
At the same time, utilities consider that despite their experience in collecting and
processing meter readings,
"dealing with more granular data generated by smart grids and
meters will carry a higher level of complexity",
while competition in shaping and trading
novel energy products to consumers
"will intensify from all sides",
including from new
actors. Suppliers welcome the changes that are coming but recognise that they
"will have
to proactively find their place in this new ecosystem".
Aggregators (SEDC)
The Smart Energy Demand Coalition (SEDC) advocates that demand-side resources
can play a crucial role in making the transition to a decarbonised energy system efficient
and affordable, and also involving in this empowered energy consumers. SEDC believes
that
"a
precondition for consumer empowerment is giving them a choice:
citizens,
commercial and industrial consumers should be able to opt for the energy services they
prefer, the services they wish to sell, and the service provider they wish to work with. This
includes the choice to valorise the flexibility of their devices and processes on the market,
the choice to self-generate electricity, or the
choice for real-time electricity pricing
to
adjust parts of their consumption
–
automated or not
–
to the variability on the market and
save costs. It also includes the
choice to work with
their energy supplier as well as
an
independent energy service provider
such as a demand response aggregator for different
services"
146
. For this to happen, SEDC recommends a set of
"coherent measures to remove
barriers currently in place and implement a long-term vision for consumer
engagement"
147
, and advises that
"the
potential of demand-side flexibility (is) adequately
included in all European scenario calculations and planning for infrastructure
developments".
Amongst its recommendations, SEDC lists the following:
(i)
"EU rules providing for access for demand-side flexibility to all energy markets
(wholesale, balancing, ancillary services and capacity) on an equal footing with
145
146
147
Eurelectric report
"The power sector goes digital - Next generation data management for energy
consumers",
May 2016;
http://www.eurelectric.org/media/278067/joint_retail_dso_data_report_final_11may_as-2016-030-
0258-01-e.pdf
Article by F. Thies SEDC Executive Director appearing under "Guest
Corner"
in EC DG ENER
Newsletter of May 2016;
https://ec.europa.eu/energy/en/energy_newsletter/newsletter-may-2016
SEDC position paper "10
Recommendations for an Efficient European Power Market Design",
2016;
http://www.smartenergydemand.eu/wp-content/uploads/2016/02/SEDC-10-recommendations.pdf
140
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generation",
and
enabling
"customers … to participate in all markets directly or through
an aggregator";
(ii)
"third party aggregators
should
access all markets without prior agreement of
the
respective
customer’s
energy retailer/Balance Responsible Party";
and
"market prices
should reflect the real value of electricity at any moment";
(iii)
"any customer should have the right to a smart meter and to choose hourly, and
where applicable quarter-hourly, market pricing;
the retailer/BRP should be settled
accordingly";
(iv)
"Distribution
System Operators should be encouraged to make use of smart demand-
side flexibility solutions
offered by market parties for system operations purposes.
Incentive structures
should be revised to this end"…, "…
network tariffs
should support,
rather than hamper the use of demand-side flexibility, and perverse incentives must be
removed".
Consumer Groups
BEUC
–
the European Consumer Association, advocates that as we are moving towards a
consumer-centric energy market, we need to ensure that we address both old and new
challenges
–
with the latter being new technologies (smart meters, connected devices,
smart homes), friendly demand-side response and new business models and new market
players. BEUC believes that
"increased
consumer engagement is an important factor for
the future energy sector.
This
requires innovative ideas
to empower consumers
backed
by an appropriate legal framework".
Also,
"new products and services
need to respond
to consumers’ demands rather than risk confusing them
further. Moreover, as new
technologies
148
make it technically possible to process much more data than as is current
practice in the energy sector, compliance with
data protection
rules and their enforcement
must be ensured"
149
.
BEUC feels that these technologies
"in general
may offer a larger choice of products and
services
as well as more information for consumers,
yet the benefits for consumers are
not guaranteed"
150
. It clarifies its rationale by noting that
"although new technologies such
as smart meters may help those who consume large amounts of electricity …,
smart meters
should not be understood as a necessity to achieve energy savings.
Therefore, instead of
pushing through this technology,
new services
(facilitated by new technologies)
or demand
response programmes should be based on understanding market opportunities and
consumer outcomes.
Consumers should also have the
right to opt out
and have their meter
operated in dumb mode. A
voluntary and consumer-centred roll-out of smart meters
rather than a mandatory one
may increase consumer participation and public support as
it facilitates ownership, data protection, security and cost allocation issues. Moreover,
where smart meters are rolled out,
minimum functionalities and interoperability are
essential
to ensure consumers have easy access to the information they need to take
148
149
150
E.g. smart meters, varying user interfaces, smart appliances and home automation
BEUC website -
http://www.beuc.eu/press-media/news-events/energy-union-what-it-consumers
BEUC position paper "Building
a consumer-centric energy union",
July 2015;
http://www.beuc.eu/publications/beuc-x-2015-068_mst_building_a_consumer-
centric_energy_union.pdf
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informed decisions on their consumption, but this is only the starting point. Further work
is needed to build trust and encourage consumer engagement. Consumers urgently need
clear commitments that the investments
to upgrade the infrastructure and the roll-out of
smart meters
will deliver benefits to them as well as monitoring and enforcement of these
commitments".
BEUC therefore calls for
"a solid legal and regulatory framework"
"…in
order to guarantee that the roll-out is cost efficient and that
costs and benefits are fairly
shared among all stakeholders who benefit from the new technology".
At this point
BEUC also notes that
" the benefits to DSOs from smart meters in regard to running,
surveillance, repairing and planning the network is often undervalued when setting the
share of costs covered by consumers via their bills".
Regarding demand response, and looking at what the near future can bring to households
in terms of demand response, BEUC states that a
"smart demand response scheme"
that
can be of interest to consumers should be
"transparent (simple and clear offers and
contracts); voluntary; rewarding flexibility and not penalising in-flexibility", "focus(ed)
on consumers' needs and experience"
151
. In fact
to guarantee consumers can benefit
from demand response,
BEUC sees that
152
(i)
"transparency
and comparability
are key to the success of new dynamic tariffs";
(ii)it is important to assess
"the degree to which consumers will likely rely on
automation
to deliver the expected benefits and … how (novel energy) services (could) accommodate
consumers’ lifestyles";
(iii)"regulators
should ensure consumers’ flexibility is
properly rewarded
and that there
are
price safeguards
when consumers are fully exposed to wholesale market
developments";
and
(iv) calls for the
"European Commission to coordinate with Member States and national
regulators a distributional analysis on the
impact of time-of-use tariffs on different social
groups
and if/how these groups can access the
benefits of new deals".
151
152
BEUC presentation at the EUSEW 2016 event "Engaged
customers driving the energy transition",
16.06.2016 -
http://eusew.eu/engaged-customers-driving-energy-transition
BEUC position paper "Building
a consumer-centric energy union",
July 2015;
http://www.beuc.eu/publications/beuc-x-2015-068_mst_building_a_consumer-
centric_energy_union.pdf
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3.2. Distribution networks
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Summary table
Objective: Enable Distribution System Operators ('DSOs') to locally manage challenges of energy transition in a cost-efficient and sustainable way, without distorting the market.
Option: 0
Option 1
Option 2
BAU
-
Allow and incentivize DSOs to acquire flexibility services from distributed
-
Allow DSOs to use flexibility under the conditions set in
Member
States
are
primarily
energy resources.
Option 1.
responsible on deciding on the detail
-
Establish specific conditions under which DSOs should use flexibility, and
-
Define specific set of tasks (allowed and not allowed) for
tasks of DSOs.
ensure the neutrality of DSOs when interacting with the market or consumers.
DSOs across EU.
-
Clarify the role of DSOs only in specific tasks such as data management, the
-
Enforce existing unbundling rules also to DSOs with less
ownership and operation of local storage and electric vehicle charging
than 100,000 customers (small DSOs).
infrastructure.
-
Establish cooperation between DSOs and TSOs on specific areas, alongside the
creation of a single European DSO entity.
Pro
Pro
Pro
Current framework gives more Use of flexible resources by DSOs will support integration of RES E in distribution Stricter unbundling rules would possibly enhance competition
flexibility to Member States to grids in a cost-efficient way.
in distribution systems which are currently exempted from
accommodate local conditions in their Measures which ensure neutrality of DSOs and will guarantee that operators do not unbundling requirements.
take advantage of their monopolistic position in the market.
national measures.
Under certain condition, stricter unbundling rules would also
be a more robust way to minimizing DSO conflicts of interest
given the broad range of changes to the electricity system, and
the difficulty of anticipating how these changes could lead to
market distortions.
Con
Con
Con
Not all Member States are integrating Effectiveness of measures may still depend on remuneration of DSOs and regulatory Uniform unbundling rules across EU would have
required changes in order to support framework at national level.
disproportionate effects especially for small DSOs.
EU internal energy market and targets.
Possible impacts in terms of ownership, financing and
effectiveness of small DSOs.
A uniform set of tasks for DSOs would not accommodate local
market conditions across EU and different distribution
structures.
Most suitable option(s): Option 1
is the preferred option as it enhances the role of DSOs as active operators and ensures their neutrality without resulting in excess administrative costs.
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Description of the baseline
Legal framework
Article 25 ('Tasks of distribution system operators') of the Electricity Directive puts
forward provisions which describe the core tasks of DSOs, as well as, specific obligations
that DSOs have to comply with. Under these provisions, DSOs are mainly responsible to
operate, maintain and develop under economic conditions a secure, reliable and efficient
electricity distribution system.
Except these core tasks, the Electricity Directive sets under Article 25(6) some specific
obligations e.g. in cases where DSOs are responsible for balancing the distribution system.
Moreover, under Article 25(7), DSOs shall consider measures such as energy efficiency
and demand-side management, in order to avoid investing in new capacity.
According to Article 41 of the Electricity Directive Member States are responsible to
define roles and responsibilities for different actors including DSOs. These roles and
responsibilities concern the following areas: contractual arrangements, commitment to
customers, data exchange and settlement rules, data ownership and metering responsibility.
Article 26 of the Electricity Directive set also unbundling requirements for DSOs similar
to Directive 2003/54/EC (the previous Electricity Directive which was part of the Second
Package). The Electricity Directive sets unbundling requirements in terms of legal form
(legal unbundling) where the DSO is a legally separate entity with its own independent
decision making board, but remains under the same ownership of a vertically integrated
undertaking ('VIU'). Under this form of unbundling it is also required that DSOs implement
functional unbundling where the operational, management and accounting activities of a
DSO are separated from other activities in the VIU. Article 31 of the Electricity Directive
also requires the unbundling of accounts (accounting unbundling) where the DSO business
unit must keep separate accounts for its activities from the rest of the VIU in order to avoid
cross-subsidisation,.
Article 26(4) of the Electricity Directive gives the option to Member States not to apply
the unbundling rules (no legal/functional unbundling) for DSOs with less than 100,000
customers. Only accounting unbundling applies to DSOs below this threshold. Member
States may choose to apply this threshold or not, or to set a lower threshold. Article 26(3)
contains obligations which seek to strengthen regulatory oversight on vertically integrated
undertakings and to mitigate communication and branding confusion.
Assessment of current situation
Electricity distribution differs widely across EU Member States in terms of the number of
DSOs in each country, voltage level of the distribution system, and tasks. According to
CEER
153
(data for 24 EU Member States) there is a total of 2,600 electricity DSOs
operating across EU (see figure 1). From these DSOs, 2,347 (around 90% of the total) fall
under the 100,000 rule and according to Article 26(4), for these DSOs, Member States are
not obliged to implement unbundling provisions under Article 26 of the Electricity
Directive.
153
"Status Review on the Transposition of Unbundling Requirements for DSOs and Closed Distribution
System Operators"
(2013) CEER.
145
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Figure 1: Number of electricity DSOs per Member State
Source: CEER (2013)
Within the framework of the Electricity Directive, Member States have to determine the
detailed tasks of DSOs. There is number of factors which may affect those tasks such as:
the structure and ownership of electricity distribution (i.e. public/private, municipalities
etc.), development of the electricity sector, size of the DSOs, voltage level of distribution
grid. For instance, in Member States with a high number of DSOs two layers of distribution
systems usually exist, local distribution systems and regional distribution systems which
connect local networks with the transmission network.
According to the Electricity Directive the core tasks of DSOs are to maintain, develop and
operate the distribution network. The Electricity Directive does not allocate other specific
tasks to DSOs such as for instance metering or data management activities. The more
specific activities are left to Member States to decide, according for instance to Article 41.
According to the Electricity Directive DSOs may also perform balancing activity, this may
be the case in some Member States for regional or larger DSOs.
Therefore, as the EU legislation leaves a quite open framework, there is a variety of tasks
for which DSOs are responsible, depending on the Member State where they are operating.
For instance, even in activities such as metering and connection that in the majority of the
Member States is traditionally performed by the DSOs, there are cases (e.g. UK) where the
activity is open to competition.
When it comes to tasks which can be performed both by TSOs and DSOs there is a mixed
picture across the EU. In general, tasks such as dispatching of generation and use of
flexibility resources are part of TSO tasks. In the majority of Member States where DSOs
can be involved in dispatching activities, this is mostly in cases of emergency in order to
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ensure security of supply. Cases where flexibility resources or interruptible contracts can
be used by DSOs are rather limited
154
.
In meeting the 2020 targets and 2030 climate and energy objectives
155
, Member States will
have to integrate a high amount of RES with an increasing number of these resources being
variable RES E (wind and solar). A large share of these resources is connected to
distribution grids (low and medium voltage); according to available data
156
this number is
estimated to be even higher than 90% in some Member States (e.g. Germany) and over
50% in others (Belgium, UK, France, Ireland, Portugal, and Spain).
Moreover, the electrification of sectors such as transport and heating will introduce new
loads in distribution networks. These elements will create new requirements and
possibilities
157
for DSOs, who will have to manage higher peaks in demand while
maintaining quality of service and minimizing network costs.
The degree of the challenge of integrating high amounts of variable RES (VRES) in
networks differs among the Member States. A group of Member States such as for example
Germany, Denmark, Spain, Portugal already have integrated significant amounts of wind
and solar power in the grid and are expecting more moderate growths rates in VRES
capacity going forward to 2030 (see figure 2). The majority of Member States have
integrated a moderate amount of wind and solar power but will experience higher growth
rates of VRES compared to the group with a high VRES ratio. A minority of Member
States have VRES ratios of less than 5% but are expected to have the highest growth rates
going forward to 2030.
Figure 2: Wind and solar growth rates and ratio to total capacity
Source: Copenhagen Economics, VVA Europe (2016).
Distribution grids will also face an increasing challenge from the integration of new loads
resulting from electric vehicles (EV) penetration and heat pumps. Currently, penetration
154
155
156
157
"Study on tariff design for distribution systems"
(2015) AF Mercados, refE, Indra.
COM(2014) 15 final
"A policy framework for climate and energy in the period from 2020 to 2030".
EvolvDSO project (Deliverable 1.1) and other sources.
On the one hand EVs and heating/cooling loads will require more network capacity, on the other hand
this kind of loads offer a huge storage potential (i.e. battery and heat storage) which can be coordinated
in order to offer flexibility services to the system.
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rates for electric vehicles are low among the European countries ranging from around 700
cars in Portugal to 44,000 cars in the Netherlands (see table 1). However, the uptake of
electric vehicles is expected to increase by over 50% per year going forward to 2030 in
several EU Member States. Germany is expected to have the highest number of electric
vehicles with over 10 million cars in 2030.
Table 1: Number of Electric Vehicles in selected countries (2014
–
2030)
Country
2014
2030 (projected)
867,000
436,000
4,263,000
517,000
6,638,000
3,735,000
10,024,000
5,431,000
429,000
982,000
743
Portugal
2,799
Denmark
3,536
Spain
6,990
Sweden
7,584
Italy
21,425
UK
24,419
Germany
30,912
France
40,887
Norway
43,762
Netherlands
Source: Copenhagen Economics, VVA Europe (2016).
Annual expected
increase
55%
37%
56%
31%
53%
38%
46%
38%
16%
21%
Cost-effectively adapting to these changes will require DSOs to use flexible distributed
energy resources (e.g. demand response, storage, distributed generation etc.) to manage
local congestion, which will also require enhancing DSO/TSO collaboration. The use of
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such flexibility for the operation and planning of the network has the potential to avoid
costly network expansions. For example, it may be significantly cheaper for a DSO to
overcome local network congestion by occasionally procuring demand response services
than to upgrade its entire network infrastructure in an area to be able to accommodate
relatively uncommon demand peaks. This is a pressing issue for the EU in light of the fact
that electricity network costs increased by 18.5% for households and 30% for industrial
consumers between 2008 and 2012
158
.
For instance, a study
159
conducted for the German distribution networks estimated that
under the current conditions and depending on different scenarios, a considerable
additional overall investment will be required. The study concludes that innovative
planning concepts in conjunction with intelligent technologies considerably reduce the
network expansion requirement
160
.
In the majority of Member States presented in table 2, DSOs cannot currently procure
flexibility services partially because there is a lack of a legal framework or because the
services are not covered in the regulated cost base.
Table 2: Status Quo on DSOs incentives to procure flexibility services
Procurement of flexibility services
Number of Member
States
8
Member state
DSOs cannot contract flexibility
services
DSOs can contract system flexibility
services for constraints management
in certain situations
Source: Copenhagen Economics, VVA Europe (2016).
FI, FR, IE, IT, PT, EL, NL, ES
3
UK, BE, DE
According to EvolvDSO project
161
most DSOs surveyed (France, Ireland, Italy, Portugal)
are not able to contract flexibility for congestion management although discussions on the
topic take place in these countries. In Belgium and Germany, DSOs have the possibility to
obtain system flexibility services via the connection and distribution access contract. These
types of contracts provide for instance a reduced network fee in exchange for the control
of the unit.
158
159
160
161
COM(2014) 21 /2
"Energy prices and costs in Europe"
"Moderne Verteilernetze für Deutschland(Verteilernetzstudie)"
(2014) E-Bridge, IAEW, OFFIS.
According to the study 90% of the capacity of installed renewable energy installations is connected up
to distribution networks. With an overall coverage of 1.7 million kilometres, these networks make up
about 98% of the overall national grid in Germany. An amount of 23 billion euros to 49 billion euros
depending on the scenario must be invested in distribution networks by 2032 for the integration of
renewable energy installations. The combination of innovative planning concepts with intelligent
technologies can halve the investment requirement and reduce by 20% the average supplementary costs.
EvolvDSO (“Development
of methodologies and tools for new and evolving DSO roles for efficient
DRES integration in distribution networks”)
is
an FP7 collaborative project funded by the European
Commission (http://www.evolvdso.eu/Home/About).
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In Belgium, such contracts apply to new production units requesting connection at HV and
MV grids. The contract allows to temporarily limit the active power of the unit via distance
control. In Germany DSOs offer these "non-firm" access contracts to controllable thermal
loads, i.e. heat pumps and overnight storage heating (EvolvDSO, 2016). Both countries are
considering broadening these contracts to also include flexibility contracts for congestion
management under normal operation state and not just emergency situations (EvolvDSO,
2016).
From data presented in the study by AF Mercados et al (2015) regarding the responsibility
of DSOs in dispatching of embedded generation, use of interruptible contracts and other
sources of flexibility, it is concluded that in most of Member States where DSOs can be
involved in dispatching this is most of the times for coping with emergency situations
(security reasons). In less than 1/3 of the Member States DSOs are using solutions such as
flexibility resources or interruptible contracts in order to address grid problems.
Deficiencies of current legislation
According to the conclusions of "Evaluation
of the EU's regulatory framework for
electricity market design and consumer protection in the fields of electricity and gas"
one
of the main objectives of the Electricity Directive was to improve competition through
better regulation, unbundling and reducing asymmetric information. In general,
unbundling measures contribute to the contestability of the retail market and thus facilitate
market entry by third party suppliers.
The risks of less unbundling link to suboptimal switching procedures in order to deter
market entry, competitive advantage which may come from the use of the same brand name
or privileged access to network information, consumption data information and cross-
subsidies.
On the other hand, discrimination for distribution network access appears to be less
relevant than at transmission level, with a possible exception of small generation connected
at distribution level. DSO unbundling is less relevant with respect to cross-border flows as
flows are more local.
CEER finds that in general the implementation of unbundling rules has been
satisfactory
162
. Regarding the implementation of the measures, CEER is reporting
problems in the implementation of the provisions related to branding and communication.
The Commission has taken action towards the proper implementation of the relevant
provisions through compliance checks and infringement procedures, requesting Member
States to ensure a clear separation of identity of the supply and distribution activities within
a vertically integrated undertaking.
Some of the factors that may influence and raise the impact of the foreseen risks are the
increased penetration of RES E generation at distribution level and introduction of smart
metering systems.
In terms of
effectiveness,
the intervention mainly aimed at the unbundling of vertical
integrated distribution companies with the objective to ensure non-discriminatory and
transparent third party access in distribution networks, in order to promote competition in
162
"Status Review on the Implementation of Distribution System Operators’ Unbundling Provisions of the
3rd Energy Package"
(2016) CEER.
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the energy market. There is no evidence that the intervention within the boundaries of the
unbundling requirements, did not achieve the objective of promoting competition in the
market.
The Electricity Directive leaves it at the discretion of Member States to decide which level
of unbundling will apply for small DSOs (less than 100,000 customers) and the detailed
tasks that DSOs should carry out at a national level. There is a quite diverse situation across
EU Member States when it comes to responsibilities of DSOs across the EU.
Provisions which aimed to enhance the DSOs position in using demand side management
and energy efficiency measures in planning their networks did not prove to be effective.
Only in few Member States, DSOs are in position to use such tools in order to avoid costly
investments and operate their networks more efficiently.
In terms of
relevance,
the original objectives of DSO unbundling requirements and the
framework in which Member States can decide on the responsibilities of operators still
correspond to the EU objective of a competitive internal energy market. The
implementation of smart metering systems (wide scale roll-out in 17 Member States) will
generate more granular consumption data and new business opportunities in the retail
market. Moreover, the introduction of more RES E generation at distribution level will
require a more active management of the network from DSOs. Even if the measures under
the Electricity Directive had included to a certain extent these developments the focus of
the intervention was not on these new needs that are estimated to grow with the completion
of smart metering systems and the installation of distributed RES E.
In terms of
coherence,
the measures are fully coherent with the objectives of the internal
energy market. Unbundling provisions for DSOs complement the relevant requirements
for TSOs, by providing a transparent and non-discriminatory framework for third party
access also at retail market level. These provisions are fundamental for the promotion of
competition in the energy market, the entrance of new energy service providers and the
development of new services.
In terms of
EU-added value,
the requirements on unbundling are fundamental for the
promotion of competition in the internal energy market. Provisions which are relevant to
DSOs have the characteristic of a permanent effect.
Gap analysis
According to the conclusions of the
"Evaluation of the EU's regulatory framework for
electricity market design and consumer protection in the fields of electricity and gas"
with
the deployment of smart metering systems across EU Member States a large amount of
data will be available to DSOs. This development requires a closer assessment and
consideration of specific measures.
In terms of DSO responsibilities, it is clear that there is a wide variety of roles and tasks
for DSOs across the EU. This situation does not allow for the application of a uniform set
of responsibilities for all DSOs, as such measure would have a disproportionate effect on
DSOs across the EU, based mostly on the variety of distribution voltage levels and number
of connected customers.
It seems however appropriate to enhance the role of DSOs when it comes to additional
tools such as the use of flexible resources in order to improve their efficiency in terms of
costs and quality of service provided to system users. Such measures however could only
be introduced with the parallel introduction of suitable provisions which prohibit DSOs to
take advantage of their monopolistic position in the market by clarifying their role in
specific activities. In the absence of such measures, the DSOs could foreclose the market
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and reduce the benefits for the system users, leading to an inefficient allocation of
resources and reduction of social welfare.
Presentation of the options
Distribution system operators
Under
Option 0
(BAU) existing provisions of the Electricity Directive will continue to
apply concerning the tasks of DSOs. In this case Member States are responsible for
deciding on a number of non-core tasks as well as on remuneration of DSOs.
Option 0+
(Non-regulatory approach) was discarded as the existing EU legislative
framework does not directly address flexibility in distribution networks. This needs to be
further codified in law in order to ensure,
inter alia,
a level playing field for the
achievement of the EU's RES E deployment objectives given new market conditions. In
addition, it is unlikely that voluntary cooperation between Member States would deliver
the desirable policy objectives in this case.
Under
Option 1
the objective is to allow the DSOs to procure and use flexibility services.
Introduce specific conditions under which DSOs should procure flexibility in order to
ensure neutrality and enable longer term investments in flexibility. Moreover, the role of
DSOs regarding specific tasks such as data management, ownership and operation of
storage and electric vehicle charging infrastructure will be clarified under this option.
Measures under Option 1 will also seek to establish an enhanced cooperation between
TSOs and DSOs in terms of network operation and planning.
Under
Option 2
measures will aim to define specific tasks that DSOs across the EU should
be allowed and not allowed to carry out. The tasks that DSOs should be allowed to carry
out would include their core tasks and tasks where there is no potential competition, while
activities which are open to competition or already forbidden (e.g. generation or supply)
should not be allowed. Also, under this option existing unbundling rules will apply also to
DSOs with less than 100,000 customers (small DSOs), abolishing the provision of the
Electricity Directive which allows Member States to exempt small DSOs from legal and
functional unbundling.
Comparison of the options
a. The extent to which they would achieve the objectives (effectiveness)
The main objective is to enable DSOs to locally manage challenges of the energy transition
in a cost-efficient and sustainable way, without distorting the market.
In general the current EU framework leaves to Member States the more detailed
identification of the distribution framework at national level in terms of the specific tasks
that DSOs should carry out and the tools available for operating and developing their grids.
However, in light of the major changes the electricity system is undergoing,
Option 0
is
likely to be inadequate in ensuring a cost efficient grid operation.
DSOs may in some countries not have access to appropriate tools in order to operate
efficiently, for instance by procuring flexibility from their customers through aggregators
or local markets, while in many countries they are not adequately incentivised through the
remuneration schemes in place to do so. The Electricity Directive requires DSOs to take
into account demand-side management and energy efficiency measures or distributed
generation as well as conventional assets expansion when planning their networks.
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However, it is up to Member States (national authorities, NRAs and DSOs) to ensure that
this is carried out. While this option provides an open EU framework for Member States,
it is also likely to lead to national specific frameworks which are not conducive to the use
of demand side flexibility at DSO level.
Moreover, there are different approaches across Member States for the use of demand side
flexibility from DSOs and a lack of market rules under which DSOs shall procure
flexibility services, while there is no clear framework regarding the involvement of DSOs
in activities such as storage or electric vehicle charging infrastructure.
The measures under
Option 1
will establish a clear legal basis for allowing DSOs to use
flexibility. Specific measures under this option will also clarify the role of DSOs in
competitive activities such as storage and electric vehicles charging, and set a specific
framework for DSO involvement. Such a regulatory framework should allow different
solutions in order to address specific needs of the network, based on market procedures
(e.g. long-term contracting of flexibility services such as large scale storage). Regarding
the involvement of DSOs in data handling, specific measures under Option 1 will ensure
neutrality of operators (see also Annexe 7.3 of the present annexes to the impact
assessment).
DSOs should harness flexibility from grid users without the risk of distorting or hampering
the development under competitive terms of distributed energy services, such as demand
response, storage, supply and generation, through discriminatory practices or monopolistic
behaviour. This Option will reduce the risk of competition distortions compared to Option
0. By defining a common framework on how DSOs can procure flexibility and perform
specific roles such as involvement in storage, a level playing field of a certain standard
will be ensured across Member States, unlike the situation where Member States adopt
different approaches to this issue. Moreover, cooperation with TSOs is important as
resources which provide flexibility to the system are located in the distribution system and
therefore coordinated operation and exchange of information between operators will be
required.
Effectiveness of this option can be limited by the fact that the differences among
distribution system structures and tasks of DSOs across the EU, will possibly require that
measures at EU level have to remain broad enough in order to accommodate diverse
situations.
Regarding the use of flexibility, the effectiveness of this option also depends on the
implementation in each Member State, as national remuneration schemes are important in
order to provide to DSOs the right incentives to use flexibility and be properly remunerated
(links to options under distribution tariffs and remuneration, see also Annexe 3.3 of the
present annexes to the impact assessment).
Option 2
foresees a uniform framework for DSOs in terms of tasks and level of unbundling
across the EU. The procurement of flexibility from DSOs will be similar to Option 1.
Stricter unbundling rules for small DSOs may lower the risk for discriminatory behaviour
and result in gains in retail competition. On the other hand, given that DSOs are natural
monopolies, such measures will not fully guarantee the avoidance of the dominant role of
DSOs in procuring flexibility from system users. Therefore, additional measures will be
needed in order to avoid monopolistic behaviour from DSOs which could lead to market
distortions.
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The definition of a uniform set of tasks applicable to all DSOs could lead to non-effective
arrangements depending on the different market conditions as such a framework would not
be able to account for the differences between distribution systems across the EU (e.g.
different retail market conditions or structural and technical differences of distribution
systems)
163
.
b. Their respective key economic impacts and benefit/cost ratio, cost-effectiveness
(efficiency) & Economic impacts
Impacts of measures under
Option 1
will be highly dependent on the detailed
implementation at national level, as for instance the extent to which DSOs under the
monitoring of the NRA will decide to supplant grid expansions with the use of flexibility
in network planning. The decision of such measures will be made on the basis of the most
beneficial solution for each distribution system taking into account avoided investments
and considering the costs of employing flexible resources.
Curtailment of RES E in grid planning as quantified in the E-Bridge et al (2014) study
164
could help reducing the grid expansion requirements caused by new RES E installations in
the future by at least 22% in the higher voltage grid (>110 kV). Those savings of 22% can
be achieved when allowing for 3% curtailment in grid planning. Considered generation for
curtailment are wind and solar power installations larger than 7 kW; that affects 52% of
all installations, whose aggregated capacity accounts for more than 90% of the total
capacity installed. The benefits
of curtailment are lower expansion
requirements for the grids,
which do not have to be built to accommodate flows corresponding to the maximum
capacity of the connected RES E installations.
Copenhagen Economics, VVA Europe (2016)
165
estimate that the total savings at EU level
from avoided distribution grid investments will be in the order of at least EUR 3.5 to 5
billion in yearly investments towards 2030 (table 3). This corresponds to a total of
approximately EUR 50-85 billion accumulated from 2016. In practice, the potential
savings could be significantly higher, to the extent which supply and demand side
flexibility measures can be used in combination rather than each measure in isolation.
163
164
165
CEER in its public consultation paper "The
future role of DSOs"
(2014), proposes a set of potential DSO
activities categorized under three broad areas (core activities, 'grey area' activities and forbidden
activities). In its conclusion paper (2015), CEER remarks that there is no single model for what a DSO
can and cannot do, but rather a number of grey areas where DSOs can participate under certain
conditions.
"Moderne Verteilernetze für Deutschland (Verteilernetzstudie)"
(2014) E-Bridge, IAEW, OFFIS.
"Impact assessment support study on: Policies for DSOs, Distribution Tariffs and Data Handling"
(2016) Copenhagen Economics, VVA Europe..
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Table 3: Avoided grid investments from flexibility
Extra grid investment from increased DG and load growth (EUR billion) yearly at EU
level
Savings from demand flexibility alone (percent)
Savings from supply flexibility alone (percent)
Savings from combination of demand and supply flexibility (percentage)
Very conservative estimate of avoided extra grid investments from flexibility
yearly at EU level (EUR billion)
Source: Copenhagen Economics, VVA Europe (2016).
11
30 - 55
44 - 55
At least 30-44
3.5 to 5
McKinsey & Company (2015)
166
found that energy storage can absorb a large share of the
power that would otherwise been curtailed even in a scenario with high share of variable
renewable power, and most of the flexibility would be located on the distribution grid level.
Decisions on which source of flexibility is more efficient should be made on the basis of
the specific needs of the network according to transparent, non-discriminatory and market-
based procedures, under close regulatory control.
Related measures are expected to create net benefits for the electricity system as they will
lower distribution costs. Moreover, the use of flexibility from distribution system operators
will stimulate the introduction of new services and the market entrance of new players such
as aggregators. Consumers will benefit from lower network tariffs (reflecting lower
distribution costs) and directly by participating in demand response programmes or other
services to the DSO.
The clarification of the EU framework regarding the role of DSOs in specific tasks such
as data handling, storage and electric vehicle charging, is expected to have positive net
benefits for the electricity system and positive economic societal net benefits. The main
reason is that these tasks can be carried out more efficiently by market players rather than
natural monopolies. Measures under this option will allow certain exemptions in cases
where a market is new (e.g. electric vehicles) or where there is no interest from market
parties to invest in such activities.
Option 2
would result in higher costs as small DSOs (serving less than 100,000 customers)
would have to implement legal unbundling criteria. Such an option would lead small DSOs
to separate distribution from the supply activity of the VIU and possibly merge with larger
DSOs, resulting in one-off and structural costs which differ per Member State. On the other
hand, main benefits would result from more transparent third party access which could
potentially have positive impacts on competition. Such costs and benefits are hard to be
fully quantified as many parameters and different local conditions should be taken into
account.
c. Simplification and/or administrative impact for companies and consumers
Option 2
for distribution system operators is expected to have high administrative costs
on the concerned energy companies because of the unbundling requirement on small DSOs
166
"Commercialisation
of energy storage in Europe"
(2015) McKinsey & Company.
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(less than 100,000 customers) which is expected to require a restructuring of those energy
companies affected by the measures.
d. Impacts on public administrations
Impacts on public administration are summarized in Section 7 below.
e. Trade-offs and synergies associated with each option with other foreseen measures
Option 1 for distribution system operators demonstrates multiple synergies with options
under demand response and smart metering. Demand response programmes through
aggregators can provide services to DSOs who wish to use flexibility in network operation
and planning.
f. Likely uncertainty in the key findings and conclusions
There is a medium risk associated with the uncertainty of the assessment of costs and
benefits of the presented options. However, it is considered that this risk cannot influence
the decision on the preferred option as there is a high differentiation among the presented
options in terms of qualitative and quantitative characteristics.
g. Which Option is preferred and why
Option 1
is the preferred option as it demonstrates the higher potential net benefits for
electricity system and society and expected to demonstrate additional benefits compared
to Option 0 without resulting in excessive costs for the involved parties. Consumers will
benefit from lower distribution costs and improved competition in the market.
Subsidiarity
EU has a shared competence with Member States in the field of energy pursuant to Article
4(1) TFEU. In line with Article 194 of the TFEU, the EU is competent to establish
measures to ensure the functioning of the energy market, ensure security of supply and
promote energy efficiency.
Under the energy transition, distribution grids will have to integrate even higher amounts
of RES E generation, while new technologies and new consumption loads will be
connected to the distribution grid. Distributed generation has the potential directly or
through aggregation to participate in national and cross-border energy markets. Moreover,
other distributed resources such as demand response or energy storage can participate in
various markets and provide ancillary services to the system also with a cross-border
aspect.
Moreover, DSOs should have the ability to integrate new generation and consumption
loads under cost-efficient terms. The access conditions for RES E generation and other
distributed resources shall be transparent and the DSO's role should be neutral in order to
create a level playing field for these resources. As the amount of resources such as RES E
generation, but in the future also other resources such as storage, will increase, the
conditions under which these resources can access the grid and participate in the national
and cross-border energy markets is expected to become more relevant.
The neutrality of DSOs when they are using flexibility to manage local congestion is a
precondition for well-functioning retail market. While electricity distribution can be
considered a local business, harmonised rules ensuring neutrality of DSOs towards other
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market actors including new energy services providers create a level playing field for RES
E development across the EU, crucial in achieving the RES E targets, and support the
completion of internal energy market.
Distribution grid issues may affect the development of the internal energy market and raise
concerns over possible discrimination among system users from different Member States
who however have access in the same energy markets. Uncoordinated, fragmented national
policies at distribution level may have indirect negative effects on neighbouring Member
States, and distort the internal market. EU action therefore has significant added value by
ensuring a coherent approach in all Member States.
Stakeholders' opinions
3.2.7.1.
Results of the consultation on the new Energy Market Design
According to the results of the public consultation on a new Energy Market Design
167
the
respondents view active distribution system operation, neutral market facilitation and data
hub management as possible functions for DSOs. Some stakeholders pointed to a potential
conflict of interests for DSOs in their new role in case they are also active in the supply
business and emphasized that the neutrality of DSOs should be ensured. A large number
of the stakeholders stressed the importance of data protection and privacy, and consumer's
ownership of data. Furthermore, a high number of respondents stressed the need of specific
rules regarding access to data.
Governance rules for DSOs and Models of data handling
Question:
"How should governance rules for distribution system operators and access to
metering data be adapted (data handling and ensuring data privacy etc.) in light of market
and technological developments? Are additional provisions on management of and access
by the relevant parties (end-customers, distribution system operators, transmission system
operators, suppliers, third party service providers and regulators) to the metering data
required?"
Summary of findings:
Regulators stress the importance of neutrality in the role of the DSOs as market facilitators.
To achieve this will require to:
-
Set out exactly what a neutral market facilitator entails;
-
When a DSO should be involved in an activity and when it should not;
-
NRAs to provide careful governance, with a focus on driving a convergent
approach across Europe.
Regulators consider that consumers must be guaranteed the ownership and control of their
data. The DSOs, or other data handlers, must ensure the protection of consumers’ data.
IFIEC considers that DSOs should not play the role of market facilitator, the involvement
of a third party is perceived to better support neutrality and a level playing field. Moreover,
coordination of TSOs and DSOs and potentially extended role of DSOs with respect to
congestion management, forecasting, balancing, etc. would require a separate regulatory
167
https://ec.europa.eu/energy/en/consultations/public-consultation-new-energy-market-design
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framework. However, IFIEC express concerns that some smaller DSOs might be
overstrained by this. Extended roles for DSO should be in the interest of consumers and
only be implemented when it is economically efficient.
EUROCHAMBERS believes that due to different regional and local conditions a one size
fits all approach for governance rules for distribution system operators is not appropriate.
The EU could support Member States by developing guidelines (e.g. on grid infrastructures
and incentive systems).
Most energy industry stakeholders (CEDEC, EDSO, ESMIG, ETP, EUROBAT, EWEA,
GEODE) believe that the role of DSOs should focus on active grid management and neutral
market facilitation. Some respondents state that the current regulatory framework prevents
DSOs from taking on some roles, such as procurer of system flexibility services and to
procure balancing services from third parties, and such barriers should be eliminated.
Also SEDC envisages that DSOs should be neutral market facilitators where unbundling
is fully implemented. However, in this scenario DSOs should not be active in markets such
as for demand response, as this would undermine their neutrality.
3.2.7.2.
Public consultation on the Retail Energy Market
According to the results of the 2014 public consultation on the Retail Energy Market
168
the
majority of the respondents consider that DSOs should carry out tasks such as data
management, balancing of the local grid, including distributed generation and demand
response, and connection of new generation/capacity (e.g. solar panels).
According to the majority of the stakeholders these activities should be carried out under
good regulatory oversight, with sufficient independence from supply activities, while a
clear definition of the role of DSOs (and TSOs), but also of the relationship with suppliers
and consumers, is required.
3.2.7.3.
Electricity Regulatory Forum - European Parliament
Relevant conclusions of the 31
st
EU Electricity Regulatory Forum:
-
"The Forum stresses the importance of innovative solutions and active system
management in distribution systems in order to avoid costly investments and raise
efficiencies in system operation. It highlights the need for DSOs to be able to
purchase flexibility services for operation of their systems whilst remaining neutral
market facilitators, as well as the need to further consider the design of distribution
network tariffs to provide appropriate incentives. The Forum encourages
regulators, TSOs and DSOs to work together towards the development of such
solutions as well as to share best practices."
168
https://ec.europa.eu/energy/en/consultations/consultation-retail-energy-market
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3.3. Distribution network tariffs and DSO remuneration
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Summary table
a. Table 1: Remuneration of DSOs
Objective: A performance-based remuneration framework which incentivize DSOs to increase efficiencies in planning and innovative operation of their networks.
Option: 0
Option 1
Option 2
BAU
Fully harmonize remuneration methodologies for all DSOs
-
Put in place key EU-wide principles and guidance regarding the remuneration of
Member States (NRAs) are mainly
at EU level.
DSOs, including flexibility services in the cost-base and incentivising efficient
responsible on deciding on the detailed
operation and planning of grids.
framework for the remuneration of
-
Require DSO to prepare and implement multi-annual development plans, and
DSOs.
coordinate with TSOs on such multi-annual development plans.
-
Require NRAs to periodically publish a set of common EU performance indicators
that enable the comparison of DSOs performance and the fairness of distribution
tariffs.
Pro
Pro
Pro
Current framework gives more Performance based remuneration will incentivise DSOs to become more cost-efficient A harmonized methodology would guarantee the
flexibility to Member States and NRAs and offer better quality services.
implementation of specific principles.
to accommodate local conditions in It would support integration of RES E and EU targets.
their national measures.
Con
Con
Con
Current EU framework provides only Detailed implementation will still have to be realized at Member State level, which A complete harmonisation of DSO remuneration schemes
some general principles, and not may reduce effectiveness of measures in some cases.
would not meet the specificities of different distribution
specific guidance towards regulatory
systems.
schemes which incentivize DSOs and
Therefore, such an option would possibly have
raise efficiencies.
disproportionate effects while not meeting the subsidiarity
principle.
Most suitable option(s): Option 1
is the preferred option as it will reinforce the existing framework by providing guidance on effective remuneration schemes and enhancing transparency
requirements
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b. Table 2: Distribution network tariffs
Objective: Distribution tariffs that send accurate price signals to grid users and aim to fair allocation of distribution network costs.
Option: O
Option 1
Option 2
BAU
Harmonization of distribution tariffs across the EU; fully
-
Impose on NRAs more detailed transparency and comparability requirements
Member States (NRAs) are mainly
harmonize distribution tariff structures at EU level for all EU
for distribution tariffs methodologies.
responsible for deciding on the detailed
-
Put in place EU-wide principles and guidance which ensure fair, dynamic, time- DSOs, through concrete requirements for NRAs on tariff
distribution tariffs.
setting.
dependent distribution tariffs in order to facilitate the integration of distributed
energy resources and self-consumption.
Pro
Pro
Pro
Current framework gives more Principles regarding network tariffs will increase efficient use of the system and A harmonized methodology would guarantee the
flexibility to Member States and NRAs ensure a fairer allocation of network costs.
implementation of specific principles.
to accommodate local conditions in
their national measures.
Con
Con
Con
Current EU framework provides only Detailed implementation will still have to be realized at Member State level, which A complete harmonisation of DSO structures would not meet
some general principles, and not may reduce effectiveness of measures in some cases.
the specificities of different distribution systems.
specific guidance towards distribution
Therefore, such an option would possibly have
network tariffs which effectively
disproportionate effects while not meeting the subsidiarity
allocate costs and accommodate EU
principle.
policies.
Most suitable option(s): Option 1
is the preferred option as it will reinforce the existing framework by providing guidance on effective distribution network tariffs and enhancing transparency
requirements
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Description of the baseline
Legal framework
According to Article 37(1) of the Electricity Directive, National Regulatory Authorities
(NRAs) are responsible for setting or approving distribution tariffs or their methodologies.
Article 37(6) and Article 37(8) of the Electricity Directive set some more specific
requirements for NRAs on tariff setting procedures and provide general principles. These
principles require tariffs or methodologies to allow the necessary investments in the
networks and ensure viability of the networks. NRAs shall also ensure that operators are
granted appropriate short and long-term incentives to increase efficiencies, foster market
integration and security of supply and support the related research activities.
Assessment of current situation
According to available data
169
allowed revenues (remuneration) for DSOs are set or
approved by regulators in the majority of Member States, with the exception of Spain (ES),
where allowed revenues are set by the Government.
In most Member States tariffs are also being set by the national regulator. However in some
countries the responsibilities are shared between the regulator and the DSO, the regulator
mainly defines the rules and approves the tariffs proposed by the DSO. Spain is the only
country where the Government sets the tariffs. Distribution tariffs are published in all
Member States. However, in Spain distribution tariffs are bundled with other tariff
components, covering costs such as renewable generation fees.
There is a wide variety of remuneration schemes and tariff structures across the EU, which
partly reflects the different situations and local conditions in Member States. With the
exception of the UK, current incentive‐based regulatory schemes place little emphasis on
the output delivered by the distributor, but for quality of service schemes. Moreover, the
following conclusions can be derived from the assessment of the current regulatory
regimes across the EU:
-
Typically DSOs are not exposed to volume risk and to the risk that their investment
turns out to be less useful than expected when they were decided, for example
because of lower than expected demand.
Revenue setting mechanisms based on benchmarking are implemented in countries
where the distribution sector is highly fragmented.
Regulators and stakeholders are generally less involved in the decision‐making
process on distribution network development, as compared to transmission.
Traditional tariff structures reflect a situation of limited availability of information
on each consumer’s responsibility in causing distribution
costs and are also affected
by affordability and fairness considerations.
In most countries, the share of distribution revenues from tariff components based
on energy is large, resulting in an asymmetry between the structure of distribution
costs (mostly fixed) and the way they are charged to consumers.
In the electricity sector the energy tariff component applied to households represent
on average 69% of the total network charge. This practice is common in most
-
-
-
-
-
169
"Study
on tariff design for distribution systems"
(2015) AF Mercados, refE, Indra..
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-
countries apart from three (The Netherlands, Spain and Sweden) where the energy
charge weights between 21% and 0%.
In the case of industrial customers the weight of the energy component is still
dominant (around 60% for both small and large industrial clients) but there is more
variability among countries and the corresponding weight ranges between 13% and
100%.
The current distribution tariff structures have been inherited from previous regulatory
regimes, when tariff structures were a simple combination of distribution and supply costs,
including fixed and variable energy costs, for services provided by a single utility. The
distribution tariff is generally based on the distributed amount of energy, occasionally in a
way that varies across times of the day and across seasons, but only rarely linked to peak
load requirements. Historically, this type of volume based pricing structure was
appropriate, as consumers with high peak load requirements also tended to be those who
consumed most energy. Going forward the total costs on the system, which are correlated
with the size of peak demand, will be less linked to total energy consumption.
Currently, the majority of DSO revenue is collected through volumetric tariffs, i.e. 69% of
the revenue for household consumers, 54% for small industrial consumers and 58% for
large industrial consumers (table 3). This also shows that most EU Member States have a
two-part tariff with a capacity and/or fixed component and a volumetric element.
Table 3: Status quo on volumetric and capacity tariffs among Member States
Tariff structure elements
Tariff component
for household
consumers
AT, CY, CZ, FR, DE,
GR, HU, IT, LU, PL,
PT, RO, SK, SI, GB
Tariff component
for small industrial
consumers
CY, CZ, FI, FR,
DE, GR, HU, RO,
SE, SK, GB
Tariff component
for large industrial
consumers
AT, CY, FI, FR,
GR, HU, PL, RO,
SE, SK, SI, NL, GB
Member states where the
volumetric element weights
over 50% of the DSO tariff
Member states where the
capacity element + fixed
charge weights over 50% of
the DSO tariff
ES, SE, NL
AT, IT, LU, PL, PT,
SI, ES, NL
CZ, DE, IT, LU,
PT, ES
EU capacity element + fixed
31%
46%
42%
component average
EU volumetric element
69%
54%
58%
average
Note: Bulgaria and Latvia are not included in the survey, Netherlands has a 100% capacity
based tariff for households and small industrial consumers as the only country in the EU.
In DK, Finland, Luxembourg and Malta time-of-use tariffs are not available for
household customers.
Source: Copenhagen Economics, VVA Europe (2016) based on Mercados (2015) and Eurelectric (2013).
Only 3 Member States (Spain, Sweden and the Netherlands) have a capacity and/or fixed
component that weighs over 50% of distribution tariff for household consumers. The
Netherlands have a 100% capacity based tariff for households and small industrial
consumers as the only country in the EU, while Romania has a 100% volumetric tariff.
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Between 6 and 8 Member States apply distribution tariffs where the capacity and fixed
tariff weighs over 50% of the tariff for small and industrial consumers.
In 17 countries a time‐of‐use distribution tariff is applied, typically for non‐residential
consumers and with daily (night/day) or seasonal (winter/summer) structure (Mercados
2015). France has implemented tariffs that can incite demand response by introducing
critical peak pricing. The critical peak pricing is for consumers with a three-phase
connection where up to 21 days a year could be selected with a 24 hours' notice signal.
Table 4: Status quo on time-of-use tariffs in Member States
Tariff elements
Time-of-use tariffs
Number of Member States
17
Member State
AT, HR, CZ, DK, FI, FR, EE,
GR, IR, LU, LT, MT, PL, PT,
SI, ES, UK
FR
1
Critical peak pricing
“Social tariff element” to
5
ES, IT, FR, GR, PT
cross-subsidize low income
consumer
Source: Copenhagen Economics, VVA Europe (2016) based on Mercados (2015) and Eurelectric
(2013).
Regarding charges applied to distributed generation there is a split picture among Member
States for which data were available. In 8 Member States, distributed generation is subject
to use of system charges while in 6 Member States no charges are applied. There is also
a diverse situation regarding the connection charges that distributed generators have to
pay with a wide variety of charging principles (i.e. shallow, deep, semi-deep or semi-
shallow).
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Table 5: Connection charges and use of system charges for distributed generation in
Member States
Member State
Connection Charge
Use of system charge
Deep
No
Austria
Shallow
Yes
Belgium
Deep
N/A
Bulgaria
N/A
N/A
Croatia
N/A
N/A
Cyprus
Deep
N/A
Czech Republic
Shallow
Yes
Denmark
Deep
N/A
Estonia
N/A
Yes
Finland
Semi-deep
No
France
Shallow
No
Germany
Shallow
N/A
Greece
Semi-shallow
N/A
Hungary
Shallow
No
Ireland
Shallow
Yes
Italy
Deep
N/A
Latvia
Semi-shallow
N/A
Lithuania
N/A
Yes
Luxembourg
N/A
N/A
Malta
Shallow
Yes
Netherlands
Shallow
N/A
Norway
Shallow
N/A
Poland
Deep
No
Portugal
Semi-deep
N/A
Romania
Deep
N/A
Slovakia
Shallow
N/A
Slovenia
Deep
No
Spain
Semi-deep
Yes
Sweden
Semi-shallow
Yes
UK
Source: THINK report "From distribution networks to Smart distribution systems" (2013).
The above data demonstrate a wide variety of distribution tariff structures for consumption
or generation across EU Member States. This wide variety of tariffs can be attributed to a
certain extent to the different local conditions and costs structures in each country;
however, distribution tariffs do not always follow specific principles or they introduce
different diverse conditions for investments for EU consumers who wish to invest in new
technologies including self-generation.
It is widely accepted
170
that the developments which are taking place in the distribution
systems such as the integration of vast amounts of variable RES E generation or the
170
See for instance the CEER conclusions paper on "The
future role for DSOs"
(2015) and the THINK
report
"From distribution networks to smart distribution systems: Rethinking the regulation of European
Electricity DSOs"
(2013).
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integration of new loads (e.g. heat pumps, electric vehicles), require distribution tariffs
which provide the right economic signals for the use and development of the system,
allocate costs in a fair way amongst system users and provide stability for investments for
DSOs and connected infrastructure.
Regarding remuneration schemes, DSOs across EU are not always encouraged through
appropriate regulatory frameworks to choose the most cost-efficient investments and
innovative network solutions. In many EU Member States the current regulation of DSOs
does not always provide the right incentives to efficiently develop and operate the grid,
and to consider new flexible resources in network planning made possible by distributed
energy resources
171
.
Moreover, different approaches are applied on how regulatory frameworks stimulate DSOs
to deploy innovative technologies. According to Eurelectric
172
in the majority of Member
States analysed (13 out of 20), the regulatory framework is either neutral or hampers
innovation and R&D
173
in distribution systems.
Deficiencies of the current legislation
The Electricity Directive provides an open framework for NRAs in Member States for
setting distribution network tariffs. The current legislation already provides some
principles on the elements that national regulators should consider when deciding on the
remuneration methodology, the allocation of costs on different system users, tariff
structure etc.
In terms of governance this framework shall continue to exist, as tariff setting is one of the
expertise areas and core tasks of NRAs. However, in the context of the rapid transformation
of the energy system, new generation technologies and new consumption loads will alter
the traditional flows of energy in the system and impact the operation of distribution and
transmission grids. Distribution tariff structures will have to induce an efficient use of the
system, while remuneration schemes have to incentivise DSOs for efficient operation and
planning of their networks. This will require further steps to be taken in EU legislation in
order to create a common basis for the development of a competitive and open retail market
and support the effective integration of RES E generation and new technologies under
equal and fair terms across Member States.
CEER
174
and ACER
175
recognise that the current regulatory frameworks applied in many
Member States may not fully address the new challenges such as the complex electricity
flows caused by small scale generation. Addressing this kind of challenges through the
171
172
173
174
175
"From distribution networks to smart distribution systems: Rethinking the regulation of European
Electricity DSOs"
(2013) THINK.
"Innovation incentives for DSOs
–
a must in the new energy market development"
(2016)
EURELECTRIC.
'Research, innovation and competitiveness' has been identified as one of the five dimensions of the
Energy Union strategy (COM(2015) 80 final). In this context, smart grids and smart home technology
are listed in the core priorities in order promote growth and jobs through the energy sector and to create
benefits for the energy consumer.
"The future role for DSOs"
(2015) CEER.
"A Bridge to 2025 Conclusions Paper"
(2014) ACER.
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regulatory framework would require the remuneration of innovative investments and the
introduction of the right incentives for flexible solutions which can contribute in solving
short-term and long-term congestions in the distribution grids
176
.
While NRAs have enough flexibility in setting distribution tariff structures which best fit
to their local conditions, often there is a lack of important principles which would lead to
a fair allocation of distribution costs amongst system users or the avoidance of implicit
subsidies amongst system users. Moreover, the right long-term economic signals to system
users which would allow for a more rational development of the network are often not in
place.
The diversity of tariff structures is also creating different conditions for system users such
as RES E generators who directly or indirectly through aggregation can participate in the
energy market. Different regulatory frameworks regarding the access conditions including
distribution tariffs of a variety of energy resources which participate in national and cross-
border energy markets could potentially distort competition in the internal energy market
and negatively affect the level of investment in RES E and new technologies.
Therefore, a further clarification of the overarching principles might be necessary
accompanied by measures which ensure the transparency of methodologies used and the
underlying costs. In this context, issues such as fees and tariffs that distributed energy
resources such as storage facilities have to pay would also need to be clarified.
A more detailed guidance to Member States should be decided on the basis of enhancing
further the effectiveness of the distribution network tariff schemes across the EU in order
to incentivise DSOs to raise efficiencies in their networks and to ensure a level playing
field for all system users connected to distribution networks.
Presentation of the options
Distribution tariffs and remuneration of DSOs (tables 1 and 2 in Section 1)
Under
Option 0
(BAU) distribution tariffs and remuneration for DSOs will continue to be
set according to the current framework and principles set in the Electricity Directive.
Regulatory authorities set or approve distribution tariffs or methodologies in the
framework of the Third Package.
A stronger enforcement and/or voluntary cooperation (Option 0+) has not been considered
as the existing framework does not provide the necessary policy tools and principles for
providing further guidance to Member States, while voluntary cooperation between
Member States could only be used for sharing best-practices.
Under
Option 1
in addition to the existing framework, measures on key EU-wide
principles and guidance regarding the remuneration of DSOs, including flexibility services
(e.g. energy storage and demand response) in the cost-base and incentivising efficient
176
The need for incentivising grid operators to enable and use flexibility, but also to improve distribution
tariffs in order to incentivise an efficient consumer response, was widely recognised amongst the
members of the Expert Group 3 (EG3) of the Smart Grids Task Force. The full analysis in included in
the 2015 report
"Regulatory Recommendations for the Deployment of Flexibility"
(https://ec.europa.eu/energy/sites/ener/files/documents/EG3%20Final%20-%20January%202015.pdf).
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operation and planning of grids will be put in place. EU-wide principles will also ensure
fair, dynamic, time-dependent distribution tariffs in order to facilitate the integration of
distributed energy resources including storage facilities and self-consumption. Such
principles could be further detailed in an implementing act providing clear guidance to
Member States.
Moreover, DSOs will have to prepare and implement multi-annual development plans, and
coordinate with TSOs on such multi-annual development plans.
NRAs in addition to their existing competences will have to periodically publish a set of
common EU performance indicators that enable the comparison of DSOs performance and
the fairness of distribution tariffs. NRAs will also have to implement more detailed
transparency and comparability requirements for distribution tariffs methodologies.
Measures under
Option 2
will aim to fully harmonize remuneration methodologies for all
DSOs at EU level, as well as distribution tariffs (e.g. structures and methodologies). Full
harmonization of tariff structures could include the definition of specific tariff elements
(capacity or energy component, fixed charge etc.), but also specific rules on the allocation
of distribution costs to the different tariff elements.
Comparison of the options
a. The extent to which they would achieve the objectives (effectiveness)
Distribution network tariffs and remuneration of DSOs (tables 1 and 2 in Section 1)
The main objective is to achieve distribution tariffs that send accurate price signals to grid
users and aim at a fair allocation of distribution network costs. Regarding remuneration of
DSOs the aim is incentivize DSOs to increase efficiencies in planning and innovative
operation of their networks.
Under
Option 0
Member States (NRAs) will continue to set tariffs and remuneration
methodologies according to the framework provided in the Electricity Directive. However,
the current tariff structures and methodologies do not always fulfil the desirable results
under the main objective. The current tariff structure in most Member States does not
sufficiently achieve the economic purpose of network tariffs. For instance tariffs do not
always reflect the costs of the grid from a particular type of behaviour, such as additional
consumption during peak load, or in other instances from beneficial behaviour, such as
charging a storage or electric vehicle to absorb a peak in variable renewable generation. In
several Member States different generation resources face different tariffs, and therefore
create an uneven playing field between resources or between markets (national or cross-
border).
Additionally, Member States are not obliged to provide clear transparency requirements
regarding the costs and methodologies for network tariffs. This creates an information
asymmetry between various players in the market and the risk of not having a clear and
predictable framework.
Therefore, under this option the development of more advanced and transparent
distribution tariff frameworks is left to Member States, facing the risk that some Member
States will not develop the appropriate regulatory framework without clear guidance.
Moreover, it may also lead to various rules and solutions, which risk not dealing with the
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issues of cost reflective use of the grid, or transparent regulatory framework and
appropriate incentives for operators.
Measures under
Option 1
aim to enhance the principles of the Electricity Directive for
setting network tariffs in order to provide a clearer guidance to Member States in achieving
the policy objectives. These principles will set a framework for fair, dynamic and time-
dependent tariffs which fairly reflect costs and facilitate the integration of distributed
energy resources.
This option could be more effective if in addition to measures to be included in the
Directive, more specific guidance will be provided to Member States through
implementing legislation. A more detailed guidance would set the framework under which
NRAs can establish fair and cost reflective tariffs and incentivise DSOs to raise efficiencies
in their networks.
Specific transparency requirements are expected to effectively enhance the level of
transparency regarding the underlying costs in tariff setting and the detailed
methodologies.
A full harmonization of distribution tariffs structures and methodologies under
Option 2
would require a uniform structure of tariffs across EU distribution networks. This option
is deemed as not effective in capturing different cost structures and various differences in
terms of technical characteristics which determine the final tariff structure. For instance,
the possible definition of specific tariff structures under this option would imply the
introduction of specific rules for the allocation of distribution costs in different tariff
components (e.g. capacity and energy components); however, a uniform tariff structure
could not accurately reflect the different characteristics of individual distribution networks
and support general policy objectives under diverse energy systems.
This option would reduce flexibility for Member States, as specific tariff elements would
be harmonised at EU level. A potential risk of this Option is that NRAs cannot fully design
distribution tariffs tailored to local needs, as they would be bound to a fully harmonized
tariff framework. Another issue with harmonisation is that a "one-size-fit-all" framework
for distribution tariffs might not exist and this would most probably result in various
inefficiencies.
b. Their respective key economic impacts and benefit/cost ratio, cost-effectiveness
(efficiency) & Economic impacts
Distribution network tariffs and remuneration of DSOs (tables 1 and 2 in Section 1)
Under
Option 1
Member States will be responsible for the detailed implementation of
distribution network tariffs and remuneration for DSOs. A more detailed guidance from
the Commission with EU-wide principles on tariff setting could enhance the benefits of
this option.
The adoption of distribution tariffs by NRAs which are cost-reflective and provide efficient
economic signals to system users will result in lower system costs. Moreover, the
introduction of time-dependent distribution tariffs across all Member States would aim at
incentivising demand response, the detailed implementation should be linked to specific
needs of each distribution system.
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Results of a 2015 study
177
show that a well-defined ToU tariff can indeed provide benefits
in terms of CAPEX and OPEX for the distribution grid. The level of impact strongly
depends on the specific characteristics of the grid and of the load/generation conditions.
Measures on transparency in tariff setting and distribution costs would increase the
performance of the agents involved in the tariff setting process resulting in an overall
higher societal benefit.
Option 2
could potentially have similar benefits as Option 1; however, if not well
designed, a fully harmonized framework could have negative impacts in some Member
States or particular distribution systems as one particular tariff methodology could not
accommodate the specificities of different distribution systems.
c. Impacts on public administrations
Impacts on public administration are summarized in Section 7 below.
d. Likely uncertainty in the key findings and conclusions
There is a medium risk associated with the uncertainty of the assessment of costs and
benefits of the presented options. However, it is considered that this risk cannot influence
the decision on the preferred option as there is a high differentiation among the presented
options in terms of qualitative and quantitative characteristics.
e. Which Option is preferred and why?
Distribution network tariffs and remuneration of DSOs (tables 1 and 2 in Section 3.3.1)
Option 1
(both for distribution tariffs and remuneration of DSOs) is the preferred option
as it will improve existing framework and provide to Member States and regulators more
concrete principles and guidance for tariff setting. Multiple benefits are expected for
consumers and resources connected to distribution systems.
Subsidiarity
EU has a shared competence with Member States in the field of energy pursuant to Article
4(1) of the Treaty on the Functioning of the European Union (TFEU). In line with Article
194 of the TFEU, the EU is competent to establish measures to ensure the functioning of
the energy market, ensure security of supply and promote energy efficiency.
Under the energy transition distribution grids will have to integrate even higher amounts
of RES E generation, while new technologies and new consumption loads will be
connected to the distribution grid. Distributed generation has the potential directly or
through aggregation to participate in national and cross-border energy markets. Moreover,
other distributed resources such as demand response or energy storage can participate in
various markets and provide ancillary services to the system also with a cross-border
aspect.
177
"Identifying energy efficiency improvements and saving potential in energy networks, including analysis
of the value of demand response"
(2015) Tractebel, Ecofys.
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The access conditions, including distribution tariffs, for suppliers, aggregators, RES E
generation, energy storage etc. shall be transparent and ensure a level playing field. As the
amount of resources such as RES E generation, but in the future also other resources such
as storage, will increase, the conditions under which these resources can access the grid
and participate in the national and cross-border energy markets is expected to become more
relevant.
Putting in place EU-wide principles on remuneration schemes will contribute in lowering
the costs of distribution and support the deployment of flexibility services across the EU.
Incentivising efficient operation and planning of distribution networks will result to an
overall reduction of distribution costs which will facilitate the cost-efficient integration of
distributed generation and support the achievement of EU RES targets. Moreover, through
common principles for incentivising research and innovation in distribution grids, can have
positive for European industry and contribute to employment and growth in the EU.
Distribution tariff issues may affect the development of the internal energy market and
raise concerns over possible discrimination among system users of the same category (e.g.
tariffs applied asymmetrically in border regions). Uncoordinated, fragmented national
policies for distribution tariffs may have indirect negative effects on neighbouring Member
States and distort the internal market, while lack of appropriate incentives for DSOs may
slow down the integration of RES, and the uptake of innovative technologies and energy
services. EU action therefore has significant added value by ensuring a coherent approach
in all Member States.
Stakeholders' opinions
3.2.7.1.
Results of the consultation on the new Energy Market Design
As concerns a European approach on distribution tariffs, the results of the public
consultation on a new Energy Market Design
178
were mixed; the usefulness of some
general principles is acknowledged by many stakeholders, while others stress that the
concrete design should generally considered to be subject to national regulation.
Distribution tariffs
Question:
"Shall there be a European approach to distribution tariffs? If yes, what aspects
should be covered; for example, framework, tariff components (fixed, capacity vs. energy,
timely or locational differentiation) and treatment of own generation?"
Summary of findings:
There are split views among the respondents regarding an EU approach to distribution
network tariffs. Some stakeholders (e.g. part of electricity consumers) believe that some
degree of harmonisation across EU would be beneficial and reduce barriers to cross-border
trade. However, only half of them advocate for a full harmonisation (e.g. specific tariff
structures), while the other half is more in favour of EU wide principles.
178
https://ec.europa.eu/energy/en/consultations/public-consultation-new-energy-market-design
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The electricity industry and few Member States are among those who consider that setting
out common principles at EU level is more advisable than a full harmonised framework
for distribution network tariffs.
On the other hand, regulators, the majority of Member States and some electricity
consumers, do not perceive that a "one fits all" solution is appropriate for distribution
network tariffs.
All stakeholders agree that future tariff design should ensure cost efficiency and a fair
distribution of network costs among grid users. The electricity industry supports the
importance of the capacity, time and location tariff components in order to enhance
network price signals and stimulate flexibility.
Member States:
National governments agree that distribution network tariffs should stimulate efficiency
and be cost-reflective, with the possibility to easily adapt to market developments. National
decisions on tariff structure and components are currently related to the division of network
costs among the different system users and to the national distribution system
characteristics (size and structure of the grid, demand profile of consumer, generation mix,
extent of smart metering, approach to distributed generation), as well as to the different
regulatory frameworks (number and roles of DSOs, national or regional distribution
tariffs). Therefore, the majority of Member States consider that no further harmonisation
of distribution tariffs at EU level is required (e.g. France, Sweden, Finland, Malta, Czech
Republic).
Some national governments are however more open to some common approach at EU
level. The Polish government proposes the possibility of continuous exchange of
regulatory experience between NRAs and information on specific tariff parameters. The
Slovak Republic would consider as beneficial a non-binding ACER recommendation on a
methodology for distribution tariffs for NRAs, which should incentivise innovation while
guaranteeing timely recovery of costs of distribution and efficient allocation of distribution
costs. The Danish government suggests that a common framework would increase market
transparency from a retail market perspective and would be a first step to harmonisation.
All national governments consider that any European harmonisation or framework for
distribution tariffs should not preclude the differences in national policies nor prevent
experimental tariff structures aiming at fostering demand side response.
Regulators:
Regulators do not perceive that “one size fits all” approach as appropriate for
distribution
tariffs. According to them, future tariff designs need to meet the following objectives:
-
To encourage efficient use of network assets;
-
To minimize the cost of network expansion;
-
To seek a fair distribution of network costs among network users;
-
To enhance the security and resilience of existing networks;
-
To work as a coherent structure, consistent with other incentives.
Electricity consumers:
Some electricity consumers (BEUC, CEPI) advocate a design of distribution grids tariffs
which encourage flexibility, reflecting the various profiles of demand response operators
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(e.g. ranging from industrial production sites to households running their solar PV unit).
They argue that a differentiated set of price signals would incentivise demand side
flexibility, but that distribution tariffs should comply with EU energy policy and that
regulators should have a common understanding of the reward benefits.
Other electricity consumers (CEFIC, IFIEC) believe that harmonising the tariff
methodology and structure would be beneficial and reduce barriers to cross-border trade.
They support a fair distribution of grid costs between grid users and not leading to cost
inefficiencies, and incentives to operators and system users in order to reduce total costs
of the electricity system.
European Aluminium is in favour of a harmonized methodology for grid tariffs for the
power intensive industry based on the properties and the contribution of the power
consumption profile to the transmission system. Such a tariff system must, however, take
into account national differences in grid system and market liquidity and maturity.
On the other hand, EURACOAL, EUROCHAMBERS and Business Europe disagree with
a harmonization approach because it would not take into account the geographic,
environmental, climate and energy infrastructure differences between Member States.
Energy industry:
Most of the stakeholders agree that an EU full harmonization approach to distribution
tariffs is not advisable, while some common EU principles are a more preferable approach.
In particular, EWEA advocates that the Commission should encourage NRAs in
identifying "best practices" rather than imposing a top down harmonisation of distribution
tariffs.
ESMIG, instead, believes that a more uniform approach across the EU would be beneficial.
A number of the respondents support the importance of the capacity (CEDEC, ENTSO-E,
Eurelectric, ETP, GEODE), time (CEDEC, EASE, ETP, EWEA, GEODE) and location
(CEDEC, ETP, EWEA, ENTSO-E) tariff components in order to enhance the network
price signals and stimulate flexibility.
The energy industry stakeholders consider that network tariffs shall reflect cost-efficiency
and fairness between consumers. They view self-generation as a positive development, but
support that prosumers should contribute to the costs of back-up generation and grid costs
and avoid that other consumers bear the burden of grid costs. In addition, they support that
system charges and other levies linked to policy costs should not artificially increase the
cost of electricity, acting as a bias penalizing consumption.
Network charges should provide DSOs with the required revenue to ensure that sufficient
network investments are realized and especially investments in smart grids and in
operational expenses improvements.
ESMIG advocates for the consideration of a "performance-based" approach, such that the
DSOs remuneration would be based on the performance of the network rather than the
volume of electricity.
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3.2.7.2.
Public consultation on the Retail Energy Market
Regarding distribution network tariffs, 34% of the respondents to the 2014 public
consultation on the Retail Energy Market
179
consider that European wide principles for
setting distribution network tariffs are needed, while another 34% are neutral and 26%
disagree.
Time-differentiated tariffs are supported by ca 61% of the respondents, while the majority
of stakeholders consider that cost breakdown (78%) and methodology (84%) of
distribution network tariffs should be transparent.
The majority of stakeholders also consider that self-generators/auto-consumers should
contribute to the network costs even if they use the network in a limited way. To this end,
ca 50% of the respondents consider that the further deployment of self-generation with
auto-consumption requires a common approach as far as the contribution to network costs
is concerned.
3.2.7.3.
Electricity Regulatory Forum - European Parliament
Relevant conclusions of the 31
st
EU Electricity Regulatory Forum:
-
"The Forum stresses the importance of innovative solutions and active system
management in distribution systems in order to avoid costly investments and raise
efficiencies in system operation. It highlights the need for DSOs to be able to
purchase flexibility services for operation of their systems whilst remaining neutral
market facilitators, as well as the need to further consider the design of distribution
network tariffs to provide appropriate incentives. The Forum encourages
regulators, TSOs and DSOs to work together towards the development of such
solutions as well as to share best practices."
European Parliament resolution of 26 May 2016 on delivering a new deal for energy
consumers (2015/2323(INI)):
"24. Calls for stable, sufficient and cost-effective remuneration schemes to guarantee
investor certainty and increase the take-up of small and medium-scale renewable energy
projects while minimising market distortions; calls, in this context, on Member States to
make full use of de minimis exemptions foreseen by the 2014 state aid guidelines; believes
that grid tariffs and other fees should be transparent and non-discriminatory and should
fairly reflect the impact of the consumer on the grid, avoiding double-charging while
guaranteeing sufficient funding for the maintenance and development of distribution
grids; regrets the retroactive changes to renewable support schemes, as well as the
introduction of unfair and punitive taxes or fees which hinder the continued expansion of
self-generation; highlights the importance of well-designed and future-proof support
schemes in order to increase investor certainty and value for money, and to avoid such
changes in the future; stresses that prosumers providing the grid with storage capacities
should be rewarded;"
179
https://ec.europa.eu/energy/en/consultations/consultation-retail-energy-market
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3.4. Improving the institutional framework
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Summary Table
Objective: To adapt the Institutional Framework, in particular ACER's decision-making powers and internal decision-making to the reality of integrated regional markets and the proposals of
the Market Design Initiative, as well as to address the existing and anticipated regulatory gaps in the energy market.
Option 0
Option 1
Option 2
Maintain
status quo,
taking into account that the implementation
of network codes would bring certain small scale adjustments.
However, the EU institutional framework would continue to be
based on the complementarity of regulation at national and EU-
level.
Adapting the institutional framework to the new
realities of the electricity system and to the
resulting need for additional regional cooperation
as well as to addressing existing and anticipated
regulatory gaps in the energy market.
Providing for more centralised institutional structures with
additional powers and/or responsibilities for the involved
entities.
Description
Lowest political resistance.
Addresses the shortcomings identified and
provides a pragmatic and flexible approach by
combining bottom-up initiatives and top-down
steering of the regulatory oversight.
Requires strong coordination efforts between all
involved institutional actors.
Pros
Addresses the shortcomings identified with
coordination requirements for institutional actors.
limited
Most suitable option(s): Option 1,
as it adapts the institutional framework to the new realities of the electricity system by adopting a pragmatic approach in combining bottom-up initiatives
and top-down steering of the regulatory oversight.
Cons
The implementation of the Third Package and network codes is
not sufficient to overcome existing shortcomings of the
institutional framework.
Significant changes to established institutional processes with
the greatest financial impact and highest political resistance.
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Description of the baseline
The institutional framework currently applicable to the internal energy market is laid out
in the Third Package. It strengthened the powers and independence of national regulatory
authorities (NRAs) and mandated the creation of an Agency for the Cooperation of Energy
Regulators (ACER) and the European Networks of Transmission System Operators
(ENTSOs)
180
, with the overarching aim of fostering cooperation amongst NRAs as well as
between transmission system operators (TSOs) at regional and European level.
Figure 1
below illustrates the key actors in the energy market based on the institutional
framework introduced with the adoption of the Third Package.
Figure 1: Key actors in the energy market institutional framework
Council of
Ministers
European
Parliament
European
Commission
Agency for the Cooperation of
Energy Regulators
(ACER)
European Networks for
Transmission System Operators
for Electricity and for Gas
(ENTSO-E and ENTSOG)
National regulatory
authorities (NRAs)
Source: European Commission
Transmission
system operators
(TSOs)
With the creation of ACER, the Third Package sought to cover the regulatory gap
concerning electricity and gas cross-border issues. Prior to the adoption of the Third
Package, this regulatory gap had been tackled with the Commission self-regulatory forums
like the Florence (electricity) forum and the Madrid (gas) forum as well as through the
180
As the current Impact Assessment and the related legislative proposals focus on the European electricity
markets, this Annex focuses on the assessment of the options with regard to the ENTSO for Electricity
(ENTSO-E).
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independent regulatory advisory group on electricity and gas set up by the Commission in
2003, the
"European Regulators Group for Electricity and Gas"
(ERGEG). ERGEG's
work positively contributed to market integration. However, it was widely recognised by
the sector
–
and by ERGEG itself
–
that cooperation between NRAs should be upgraded
and should take place within an EU body with clear competences and with the power to
adopt regulatory decisions.
To this end, the Third Package entrusted ACER with a wide range of tasks and
competences, including:
-
-
-
-
-
-
promoting cooperation between NRAs;
participating in the development and implementation of EU-wide network rules
(network codes and guidelines);
monitoring the implementation of EU-wide 10-year network development plans;
deciding on cross-border issues if national regulators cannot agree or if they jointly
request ACER to intervene;
monitoring the functioning of the internal market in electricity and gas; and
oversight over ENTSOs.
Based on the adoption of subsequent legislation on market transparency
181
and trans-
European infrastructures
182
ACER has been given additional responsibilities in these areas.
The Third Package established ACER with the main mission to ensure that regulatory
functions performed by NRAs at national level are properly coordinated at EU level and,
where necessary, completed at EU level. As regards its governance structure
183
, ACER
comprises a Director, responsible for representing the Agency, for the day-to-day
management and for tabling proposals for the favourable opinion of the Board of
Regulators
184
. ACER's regulatory activities are formed in the Board of Regulators,
composed of senior representatives of the NRAs of the 28 Member States. Its
administrative and budgetary activities fall under the supervision of an Administrative
Board, whose members are appointed by European Institutions. The Board of Appeal is
part of the Agency but independent from its administrative and regulatory structures, and
deals with complaints lodged against ACER decisions
185
. As regards the internal decision-
making, ACER decisions on regulatory issues (e.g. opinion on network codes) require the
favourable opinion of the Board of Regulators, which decides with two-thirds majority.
In relation to the creation of ENTSOs, the Third Package sought to enhance effective
cooperation among TSOs in order to address the shortcomings and limitations shown by
181
182
183
184
185
Regulation EU No 1227/2011 on Wholesale Energy Market Integrity and Transparency
–
REMIT; OJ
L 326, 8.12.2011, p.1
Regulation (EU) No 347/2013 on guidelines for trans-European energy infrastructure (TEN-E
Regulation).
See Article 3 of the ACER Regulation and related provisions.
Under Articles 5, 6, 7, 8 and 9 of the ACER Regulation.
The ACER Board of Appeal takes its decisions with qualified majority of at least four of its six members;
it convenes when necessary; its members are independent in their decisions; some of its costs are
envisaged in the ACER budget.
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the voluntary initiatives adopted by TSOs (the European Transmission System Operators
and Gas Transmission Europe). As a result, the Third Package tasked the ENTSOs with
EU-level functions such as contributing to the development of EU-wide network rules,
developing the 10-year network development plan and carrying out seasonal resource
adequacy assessments.
The establishment of ACER and the ENTSOs in order to enhance the cooperation among
NRAs and TSOs from 28 different Member States has undoubtedly been successful. Both
ACER and the ENTSOs are important partners in discussions on regulatory issues. Further,
the Third Package established a framwork for the ACER oversight of ENTSO-E, tasking
ACER e.g. with providing opinions on ENTSO-E's founding documents, on the network
code and network planning documents developed by ENTSO-E. In addition, the Agency
has the obligation to monitor the execution of the tasks of ENTSO-E
186
.
As regards its financing, ACER benefits from a Union subsidy set aside specifically in the
general budget of the European Union, like most EU decentralised agencies. In addition,
ACER can collect fees for individual decisions
187
.
Network Codes and Guidelines
The Third Package has set out a framework for developing network codes with a view to
harmonising, where necessary, the technical, operational and market rules governing the
electricity and gas grids. Under this framework, ACER, the ENTSOs and the European
Commission have a key role and need to work in close cooperation with all relevant
stakeholders on the development of network codes. The areas in which network codes can
be developed
188
are set out in Article 8(6) of the Electricity Regulation and of the Gas
Regulation. Once adopted, these network codes become binding Commission Regulations,
directly applicable in all Member States.
The network code process is defined in Articles 6 and 8 of the Electricity and the Gas
Regulations and it can be essentially divided in two phases: (i) the development phase; and
(ii) the adoption phase.
Figure 2
below illustrates the main stages of the network code development phase. It is
important to note that during each of these stages, the Commission, ACER and the
ENTSOs consult the proposals with stakeholders
189
.
186
187
188
189
Art. 6 of ACER Regulation.
Art. 22 of ACER Regulation. However, the fee has to be set by the European Commission, which did
not take place yet.
E.g., network connection, third party access, interoperability capacity allocation and congestion
management rules, etc.
These stakeholder consultations are not always required. For example, consultation is a requirement as
regards the preparation of the annual priority list (see Art. 6(1) Electricity Reg.) and the preparation of
the framework guidelines (Art. 6(3) Electricity Reg.). During the preparation of the network codes, the
ENTSOs have carried out stakeholder workshops, although this is not formally required in the Electricity
or Gas Regulations. In addition, the Agency may consult with stakeholders during the 3 months period
for revision of the ENTSO proposal and the preparation of the reasoned opinion (Art. 6(7) Electricity
Reg.).
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Figure 2: Main stages of the network code development process
Source: ACER
Once ACER submits a network code to the Commission recommending its adoption, the
Commission starts the adoption phase ("Commission adoption phase"), illustrated in
Figure 3
190
.
190
Network codes are adopted according to Art. 5a (1) to (4) of Decision 1999/468/EC ("regulatory
procedure with scrutiny"),
which requires a positive vote by a qualified majority of Member States and
agreement from Council and Parliament.
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Figure 3: Network code adoption phase
Source: unknown
The European Commission has also the possibility to develop "guidelines" which,
similarly to network codes, form legally binding Commission Regulations. The guidelines
have a different legal basis and follow a different development process
191
, under which
there is no formal role for ACER or ENTSO-E, while their adoption phase is the same as
for the network codes.
Once adopted, network codes and guidelines are both acts implementing the Electricity
and the Gas Regulations. There is no difference as concerns their legally binding effects
and direct applicability.
Deficiencies of the current legislation
The Third Package institutional framework aims at fostering the cooperation of NRAs as
well as between TSOs. Since their establishment, ACER and the ENTSOs have played a
key role in the progress towards a functioning internal energy market. In 2014, the
Commission undertook its first evaluation of the activities of the Agency
192
and concluded
that ACER has become a credible and respected institution playing a prominent role in the
EU regulatory field while focusing on the right priorities
193
. Also, according to ACER
194
,
191
192
193
194
The areas in which guidelines can be developed are set out in Art. 18 (1), (2), (3) Electricity Regulation
and Art. 23 (1) Gas Regulation.
In line with Art. 34 ACER Regulation. The Commission prepared this evaluation with the assistance of
an independent external expert and including a public consultation. The evaluation covered the results
achieved by the Agency and its working methods.
"Commission evaluation of the activities of the Agency for the Cooperation of Energy Regulators under
Article 34 of Regulation (EC) 713/2009"
(22. 1. 2014), European Commission,
https://ec.europa.eu/energy/sites/ener/files/documents/20140122_acer_com_evaluation.pdf
"Energy Regulation: A Bridge to 2025 Conclusions Paper"
(19 September 2014) ACER Report.
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both ENTSOs have achieved a good level of performance since their establishment by the
Third Package.
However, the recent developments in the European energy markets that the current Impact
Assessment reflects upon and the related proposals of the Market Design Initiative require
the adaptation of the institutional framwork. In addition, the implementation of the Third
Package has also highlighted areas with room for improvement concerning the framework
applicable to ACER and the ENTSOs.
The Agency has limited decision-making powers, as it acts primarily through
recommendations and opinions. With the integration of the European electricity markets
more and more cross-border decisions will be necessary (e.g. market coupling). Such
decisions however require a strong regulatory framework, for which a fragmented national
regulatory approach has proved to be insufficient
195
. Ultimately this fragmented regulatory
oversight might constitute a barrier to the integration of the energy markets
196
. In this
regard, there is consensus among market parties and stakeholders that ACER should indeed
be enabled to more efficiently deal with cross-border issues
197
and to take decisions
198
.
Moreover, as European energy markets are more and more integrated, it is crucial to ensure
that ACER can function as swiftly and as efficiently as possible. As most of the regulatory
decisions require the favourable opinion of the Board of Regulators, it is equally relevant
that the NRAs represented in the Board of Regulators can find agreements swiftly and
efficiently, which in the past was not always the case, leading to delays or to a situation
195
196
197
198
The existing competences of ACER for taking decisions set out in the ACER Regulation do not include
the implementation of network codes and guidelines. Many trading or grid operation methods to be
developed under network codes or guidelines require common EU-wide decisions or regional decisions.
Given that ACER does not have competence to take EU-wide or regional decisions relating to network
codes and guidelines, currently NRAs have to decide unanimously on the adoption of identical legal acts
in all national legal systems within a six-month period. This renders the implementation of network
codes and guidelines complex and inefficient.
"Energy Union. Key Decisions for the Realisation of a Fully Integrated Energy Market"
(2016), Study
for the Committee for Industry, Research and Energy of the European Parliament: "In
several regional
or EU-level projects (e.g. market coupling projects, see our case study in Annex 3) national authorities,
TSOs, regulators and energy exchanges of different Member States need to cooperate. However, as they
are primarily responsible for their own national gas and electricity system and market they are not
always sufficiently motivated to also take supranational interests into account.
[…]
This leads to
complex and slow decisional and implementation processes for most cross-border projects, resulting in
delayed implementations (e.g. the intra-day
markets’ coupling project)."
In this context, different
stakeholders argue for stronger governance at EU level. For example, EPEX Spot states the need to
accompany the electricity EU target model by appropriate governance architecture at European level,
applicable on market coupling activities, which will be crucial to ensure an efficient day-to-day operation
of such complex mechanisms.
"Energy Union. Key Decisions for the Realisation of a Fully Integrated Energy Market"
(2016), Study
for the Committee for Industry, Research and Energy of the European Parliament.
For instance, the Third Package does not define a regional regulatory framework beyond the generic
reference to the need for NRAs to cooperate at regional level supported by ACER, which would be
necessary to ensure proper oversight of regional entities or functions.
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where the sufficient majority could not be reached, making it impossible for ACER to fulfil
its role.
As mentioned in Section 2 above, the Third Package introduced network codes as tools for
developing EU-wide technical, operational and market rules. While this process has proved
very sucessful overall, the practice of the last 5 years has highlighted the existence of
structural insufficiences. As an example, ENTSO-E plays a central role in developing EU-
wide market rules. Therefore, the rules on its independence and transparency have to be
strong and have to be accompanied by appropriate oversight rules to ensure the transparent
and efficient functioning of the organisation. The reinforcement of these rules was also
strongly requested by a high number of stakeholders in the Commission's public
consultation on the market design initiative. Some stakeholders have mentioned that there
is a possible conflict of interest in ENTSO-E’s
role –
being at the same time an association
called to represent the public interest involved e.g., in network code drafting, and a lobby
organisation for TSOs with own commercial interests
–
and requested the adoption of
measures to address this conflict
199
.
The Third Package also includes elements of oversight of ENTSO-E by ACER. However,
given the strong role ENTSO-E plays as a technical expert body, in particular in the
development and implementation of network codes and guidelines, ACER's oversight has
proved to be insufficient, for example as regards ENTSO-E's statutory documents or as
regards the delivery of data to the Agency
200
. Moreover, the emergence of new entities and
functions of EU-level or regional relevance through the adoption of network codes and
guidelines has further enlarged this oversight gap. This is, for example, the case with the
nominated electricity market operators ('NEMOs'), the market coupling operator ('MCO')
function, which will together be responsible for performing cross-border day-ahead and
intraday trading, a role created under the CACM Guideline, and regional security
coordinators ('RSCs') in electricity. The creation of these new entities and functions has
not been accompanied by tailored regulatory oversight.
The ACER Board of Appeal has a crucial function in safeguarding the validity of the
Agency's decisions. Even though the Board of Appeals has been called upon only in a very
limited number of times since the establishment, it has proved that its independence is
crucial. Experience shows that its functioning and financing must be reaffirmed to ensure
its full independence and efficiency.
Like most of the EU decentralised agencies, ACER benefits from a Union subsidy set aside
specifically in the general budget of the European Union. As explained in Section 2, ACER
has been tasked with additional functions since its establishment. These tasks have been
199
200
For example by Eurelectric, EFET, CEDEC, Europex. This issue was also raised among the observations
of the European Court of Auditors in its report
"Improving the security of energy supply by developing
the internal energy market: more efforts needed" (2015),
which stated:
"This is problematic because,
although the ENTSOs are European bodies with roles for the development of the internal energy market,
they also represent the interests of their individual members."
ACER exerts limited oversight (opinion on status, list of members and rules of procedures as per Art. 5
of the Electricity Regulation and monitoring of ENTSO-E’s
tasks as per Art. 9 of the Electricity
Regulation.
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accompanied with additional staff. However, ACER is also subject to the programmed
reduction of staff in decentralised agencies by 5% over a period of 5 year set out in the
Commission's communication on
"Programming of human and financial resources for
decentralised agencies 2014-2020"
201
. It is clear that any additional tasks for ACER as
envisaged in the proposed initiatives will further tighten its financing and staffing and will
require further resources.
Another set of shortcomings can be tracked to insufficient participation of DSOs within
the institutional framework. Under the energy transition, a traditional top-down,
centralised electricity distribution system is being outpaced by more decentralised
generation and consumption. The integration of a significant share of variable solar and
wind generation capacity connected directly to distribution networks create new
requirements and possibilities for DSOs, who will have to deal with increased capacity
while maintaining quality of service and minimizing network costs. In addition, the
electrification of sectors such as transport and heating will introduce new loads in
distribution networks and will require a more active operation and better planning.
The problem is aggravated by the fact that specific requirements on TSO
–
DSO
cooperation as set forth in the different Network Codes and Guidelines, and new challenges
that TSOs and DSOs are jointly facing, will require greater coordination between system
operators.
For the time being, no provision at all is made for the formal integration of DSOs into the
EU institutional decision making. However, from a policy perspective a cohesive and
consistent participation of DSOs in the EU institutional framework is required. Future
electricity system will require a more coordinated approach of TSOs and DSOs on issues
of mutual concern. Regarding network codes, DSOs will need to display a common
approach, as many of the envisaged network codes are directly or indirectly concern
distribution grids.
As set out in the evaluation report
202
, while the principles of the Third Package achieved
its main purposes, new developments in electricity markets led to significant changes in
the market functioning in the last five years. The existing rules defining the institutional
framework are not fully adapted to deal with the recent changes in electricity markets
effectively. Therefore, it is reasonable to update these rules so that they may be able to cope
with the reality of today's energy system.
The institutional framework currently applicable to the internal energy market as set out in
the Third Package is based on the complementarity of regulation at national and EU-wide
level. In view of the developments since the adoption of the Third Package as described in
the evaluation report, the institutional framework, especially as regards cooperation of
NRAs at regional level, will need to be adapted to ensure the oversight of entities with
regional relevance. Moreover, as the European energy markets are more and more
201
202
Communication from the Commission to the European Parliament and the Council, COM(2013)519
final of 10.07.2013.
Evaluation Report covering the evaluation of the EU's regulatory framework for electricity market
design and consumer protection in the fields of electricity and gas and evaluation of the EU rules on
measures to safeguard security of electricity supply and infrastructure investment (Directive 2005/89).
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integrated, it is crucial to ensure that ACER can function as swiftly and as efficiently as
possible. In addition, the implementation of the Third Package has highlighted areas with
room for improvement concerning the framework applicable to ACER and the ENTSOs.
Presentation of the options
Option 0: Business as usual
The business as usual (BAU) option does not foresee new, additional measures to adapt or
improve the institutional framework. Apart from the continued implementation of the
Third Package and the implementation of network codes and guidelines, this option would
leave the EU institutional framework unchanged, meaning that it would continue to be
primarily based on a close complementarity of regulation at national and EU-wide level.
The challenges arising through the changes to and the stronger integration of the European
energy markets could not be tackled and regulatory gaps arising from the adoption and
implementation of network codes and guidelines would also remain unaddressed. This
could potentially lead to delays in their implementation and ultimately act as a barrier to
achieving the electricity EU target model.
The BAU option would maintain the limitation of ACER's decision-making powers and
would not remedy the risks arising from the fragmented national regulatory approach.
NRAs and ACER would continue to face difficulties fulfilling their tasks that have
relevance at regional and EU level.
The business as usual option would leave ACER's current internal decision-making
unchanged. This would mean that where the favourable opinion of the Board of Regulators
is necessary, this would have to be reached with two-thirds majority facing the risk of
delays or lack of agreement.
Under this option the process of developing network codes would remain unchanged. This
would allow ENTSO-E to continue playing a very strong role in setting European market
rules, going beyond of that providing technical expertise. This option would neither
improve the rules on ENTSO-E's transparency and independence nor the rules of ACER's
oversight of ENTSO-E. The progress concerning ENTSO-E's transparency would depend
on the voluntary initiative of the association. The criticisms to the existence of conflicts of
interest regarding the roles of ENTSO-E, particularly as regards the development of
network codes, would not be addressed.
Under the Option business as usual, despite having been assigned additional
responsibilities since its establishment, ACER would still be constrained by the current
regulatory framework as regards the regulatory oversight of new entities and functions
performing at regional or EU level.
This Option would maintain the current framework for the functioning of ACER's Board
of Appeal. This means that its independent functioning and financing would continue to
be highly vulnerable.
The BAU also foresees no integration of DSOs into the institutional decision-making
setting as explained under the Section dealing with the shortcomings of current legislation.
It is true that in 2015, with the support of the Commission, the four European DSO
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associations and ENTSO-E established a cooperation platform
203
between TSOs and DSOs
at EU level. This cooperation has the objective to work on issues of mutual DSO-TSO
concern such as coordinated access to resources, regulatory stability, grid visibility and
grid data. However, this cooperation remains purely voluntary in nature with no formal
expression in the wider EU decision making setting or ACER.
In sum, European DSOs collaborate through the existing DSO associations but without
any legal status at EU institutional level. There is no formal participation in drafting or
amending of network codes and guidelines.
Option 0+: Non-regulatory approach
Under this option a "stronger enforcement" approach and voluntary collaboration as a non-
legislative measure were considered without foreseeing any new, additional measures to
adapt the institutional framework. Improved enforcement of existing legislation would
entail the continued implementation of the Third Package and the implementation of
network codes and guidelines
–
as described under option business as usual
–
combined
with stronger enforcement. However, stronger enforcement would not provide any
improvement to the current institutional framework as it is already fully implementing the
existing legal framework.
Collaboration in the current institutional framework is based on legal obligation. While
voluntary cooperation might be possible in areas not covered under the Thrid Energy
Package, it would require establishing parallel structures and additional resources without
significantly improving the functioning of the current regulatory framework. Therefore,
voluntary collaboration is not considered a valid option.
Therefore, the Option 0+ would leave the EU institutional framework unchanged, meaning
that it would continue to be based, primarily, on a close complementarity of regulation at
national and EU-wide levels. Furthermore, any improvement compared to the current
situation would have to stem from voluntary initiatives of the involved bodies. In addition,
this option could not provide the necessary solutions arising from the changing market
reality as described in this impact assessment. Therefore, this option is discarded as not
valuable in providing solutions for the described shortcomings and overall developments.
Option 1: Upgrade the EU institutional framework
Option 1 foresees adapting the EU institutional framework to the new realities of the
electricity system
204
and to the resulting need for additional regional cooperation and to
address the existing and anticipated regulatory gaps in the energy market, providing
thereby for flexibility by a combination of bottom-up and top-down approaches. Option 1
would adapt the institutional framework set out in the Third Package to address the
regulatory gaps materialising through the implementation of the Third Package and
resulting from the adoption and implementation of network codes and guidelines. It would
203
ENTSO-E, CEDEC, GEODE, EDSO, EURELECTRIC (2015), "General
Guidelines for reinforcing the
cooperation between TSOs and DSOs"
(http://www.eurelectric.org/media/237587/1109_entso-
e_pp_tso-dso_web-2015-030-0569-01-e.pdf)
204
As further detailed in Section 1 of the main body of this impact assessment.
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also adapt the institutional framework to the new realities of the electricity system and to
the resulting need for additional regional cooperation.
As regards ACER’s decision-making,
Option 1 would largely entail reinforcing its powers
to carry out regulatory functions at EU level. In addition, in order to address the existing
regulatory gap as regards NRAs' regulatory functions at regional level, the policy
initiatives under this option would set out a flexible regional regulatory framework to
enhance the regional coordination and decision-making of NRAs. This Option would
introduce a system of coordinated regional decisions and oversight for certain topics by
NRAs of the region (e.g. ROCs and others deriving from the proposed market design
initiatives) and would give ACER a role for safeguarding the EU-interest.
Option 1, while giving ACER additional powers, would also ensure that the Agency can
swiftly and effectively reach these decisions in its Board of Regulators. To enable NRAs
to take decisions without delay in the BoR, this Option would adapt the BoR internal voting
rights. Option 1 also reflects on the necessity to ensure that all (existing and proposed)
ACER decisions are subject to appeal and that the ACER Board of Appeal can act fully
independently and effectively through adjusting its financing and internal rules.
Further, concerning ACER's competences, Option 1 entails strengthening ACER's role in
the development of network codes, particularly as regards giving the Agency more
responsibility in elaborating and submitting the final draft of the network code to the
Commission, while maintaining ENTSO-E's relevant role as a technical expert. This
Option would also involve strengthening ACER's oversight over ENTSO-E. In addition,
Option 1 would effectively distinguish ENTSO-E’s
statutory mandate from defending its
member companies' interests by setting out a clear European mandate in the legislation and
ensuring more transparency in its decision-making processes.
Under this Option, ACER would receive additional competence to oversee new entities
and functions which are not currently subject to regulatory oversight at EU level. This is
the case for power exchanges operating in their cross-border functions; they play a crucial
role in coupled European electricity markets and perform functions that have
characteristics of a natural monopoly. Depending on the type of entity or function and their
geographical scope, this Option would either introduce NRAs’ coordinated regional
oversight with support and monitoring by
ACER or ACER oversight with NRAs’
contribution.
As described in this Section, Option 1 would give ACER additional tasks and powers while
acknowledging that appropriate financing and staffing is key for ACER to perform its role.
Therefore, Option 1 foresees additional sources of financing which would be possible
either by increasing the EU financing or by introducing co-financing, complementary to
the Union financing the sector ACER is supervising
205
.
205
The Commission’s aim for decentralised agencies is to eliminate EU and national budgetary
contributions and wholly finance them by the sector they supervise, see the Mission letter of
Commissioner Hill of 1 November 2014. In this sense ACER could be co-financed through the sector it
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This Option would also include a formal place for DSOs to be represented at EU level, in
line with an increase in their formal market responsibilities and role as has been mentioned
above. The establishment of an EU DSO entity will enable the development of new policies
which can positively affect the cost efficient integration of distributed energy resources
including RES E, and which will reinforce the representation and participation of EU DSOs
at an institutional European level.
Option 1 thus envisages the establishment of an EU DSO entity for electricity with an
efficient working structure. European DSOs will provide experts based on calls for
proposals issued by the EU-DSO. European DSOs will participate in financing the EU-
DSO entity through a Supporting Board based on the existing EU DSO associations
(Eurelectric, EDSO, CEDEC, GEODE).
Tasks of the EU DSO will include:
-
-
-
-
Drafting network codes/guidelines following the existing procedures;
Monitor the implementation of network codes on areas which concern DSOs;
Deliver expert opinions as requested by the Commission;
Cooperate with ENTSO-E on issues of mutual concern, such as data
management, balancing, planning, congestion, etc.
The EU DSO entity will also work on areas such as DSO/TSO cooperation, integration of
RES, deployment of smart grids, demand response, digitalisation and cybersecurity.
Option 2: Restructure the EU institutional framework
Option 2 would significantly restructure the institutional framework, going beyond
addressing the regulatory gaps identified above and moving towards more centralised
institutional structures with additional powers and responsibilities at European level,
particularly as regards the role of ACER and ENTSO-E.
Concerning ACER's powers, Option 2 would extend ACER's decision-making powers to
all regulatory issues with cross-border trade relevance. This would result in ACER taking
over most NRA responsibilities directly or indirectly related to cross-border and EU-level
issues. This Option would further give the ACER Director the power to become the main
decision-making instance in the Agency, as opposed to the BoR, possibly with veto powers
from the Board of Regulators on certain measures.
As regards ACER's competences, Option 2 would entail a direct oversight over ENTSO-E
and over other entities fulfilling EU level or regional functions, giving ACER the power
to take binding decisions.
In order for ACER to perform its role under Option 2, it would require a significant
reinforcement of ACER's budget and staff as this would make a strong concentration of
is supervising. In the light of ACER’s cruacial role in delivering on the common EU objectives and in
particular in protecting the Eurpean energy markets from fraud, the functioning of ACER could be co-
financed with contributions
from market participants and/or public bodies benefitting from ACER’s
activities. This would contribute to guaranteeing ACER's full autonomy and independence.
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experts in ACER necessary. Therefore, this option would entail
–
as foreseen under Option
1
–
reinforcing EU funding and the possibility to introduce in addition financing through
market players and/or public bodies. As Option 2 would give ACER such strong powers it
would also entail a significant reinforcement of the structural set-up of the Board of Appeal
to ensure that the appeal mechanism can function independently and effectively because it
would potentially face a significantly higher number of appeals due to the increasing
number of direct ACER decisions foreseen under this Option.
As regards to ENTSO-E's competences, this option would require a formal separation of
ENTSO-E from its members' interest. It would strengthen the independence of ENTSO-E
by introducing a European level decision-making body who would have powers to decide
on proposals and initiatives without requiring prior TSOs' approval.
With regards to the role of DSOs, the measures included under Option 1 would apply to
Option 2 as well. The move to an EU regulator with full powers would however mean that
ACER would have to also carry out the oversight of, and entertain relations with, DSOs in
a way that is now done at Member State level.
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Table 2: Detailed overview of the measures proposed under the three options
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ISSUE
Option 0: Business as
usual
Option 1: Ugrade EU
insitutional framework to
address regulatory gaps
ACER decisions with BoR
favourable opinion, also
replacing
Guideline
implementing “all NRA”
decisions at EU and regional
levels
Framework of regional NRA
decision-making with ACER
oversight (complementary
role to safeguard EU interest)
Option
Restructur
institutional
framework
2:
EU
ACER decision-
making
Limited,
through
recommendations
and
opinions
Most regulatory decisions
with BoR favourable
opinion
ACER Director manages
ACER
and
tables
proposals
for
BoR
favourable opinion
ACER
decision
without
BoR
involvement, mainly
by ACER Director
BoR
decision-
making
2/3
rds
majority for the most
of ACER decisions
Independent body for all
appeal cases
Some of its costs are
envisaged in the ACER
budget
Simple majority for most of
ACER decisions
Independent body for all
appeal cases with strengthend
framework and separate
budget line in the ACER
budget
2/3
rds
majority for
ACER decisions in a
limited instances
Independent body for
all appeal cases with
strengthend line of
financing
and
framework
Board of Appeal
ACER Financing
Community/EU-funding
(separate budget line)
Possibility for ACER to
collect fees for individual
decisions
Need for increased financing
(possibly through increased
EU-funding and possibly co-
financing by contributions by
market participants and/or
national public authorities
Need for significantly
increased financing
(possibly
through
increased EU-funding
and possibly co-
financing
by
contributions
by
market participants
and/or national public
authorities
Based on ACER’s
framework guideline
ENTSO-E
drafts
network code with the
involvement
of
standing stakeholder
body,
ACER
consolidates
the
network code (ACER
internal
decision
without Board of
Regulators'
favourable opinion)
and submites the final
product
to
the
Commission
Network
Code
development
process
Based
on
ACER’s
framework
guideline
ENTSO-E drafts network
code (strong role and
influence),
ACER
provides opinion and
recommendation to the
Commission.
Based
on
ACER’s
framework
guideline
ENTSO-E drafts network
code guided by a standing
stakeholder body and broad
general
stakeholder
involvement,
ACER
consolidates the network
code and submites the final
product to the Commission
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Oversight
ENTSO-E
of
Limited ACER oversight
of ENTSO-E
None or limited regulatory
oversight (limited rules in
network
codes
and
guidelines)
Lack of clear European
mission and voluntary
transparency rules
Strenghtened
ACER
oversight of ENTSO-E
Strenghtened
oversight by
ACER
regulatory
NRAs and
Strenghtened ACER
oversight of ENTSO-
E
ACER
oversight
direct
Oversight of new
entities
ENTSO-E’s
mission
and
transparency
Codified clear European
mission and transparency
obligations on its decision-
making
Establishment of an EU DSO
entity for electricity with an
efficient working structure;
European DSOs will provide
experts based on calls for
proposals issued by the EU-
DSO.
Formal
separation
from its members'
interests and creation
of a decision-making
body
Same as Option 1,
plus an increased role
for coordination and
oversight on the part
of ACER
DSO
European
DSOs
collaborate through the
existing DSO associations
but without any legal
status at EU institutional
level. There is no formal
participation in drafting or
amending of network
codes and guidelines
Source: European Commission
Comparison of the options
As stated above, the goal of the proposed initiatives is to adapt the institutional framework
to the reality of integrated regional markets. In this regard, as it will be further illustrated
below, Option 0, the business as usual option, would not contribute towards achieving this
objective and in some instances it may even be detrimental, since the institutional
framework needs to be able to provide tools for the different parties (ACER, NRAs,
ENTSO-E) to address the challenges arising from the integration of the markets.
Options 1 and 2 can capture the challenges and potential opportunities, but the efficiency,
effectiveness and economic impact of these options can vary significantly.
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Table 3: Qualitative comparison of Options in terms of their effectiveness, efficiency
and coherence of responding to specific criteria
Criteria
Option 0:
Business as usual
Option 1:
Upgrade EU institutional
framework addressing
regulatory gaps
+
Using
expertise
established actors
from
Option 2:
Restructure EU
institutional framework
+
Efficient through limited
coordination requirements
Quality
0
Progress
remains
limited and primarily
voluntary
Speed of
implemen-
tation
-
Slow,
primarily
voluntary progress
-
Efficiency
established
limited.
0
Existence of insufficient
rules
and regualtory
gaps for organisation
of
processses
0/+
Building upon established
structures
++
Can build upon established
structures
-
Delays
resulting
changed structure
-
Requires building up new
structures/processes
from
Use of
established
institutional
processes
Efficient
organisational
structure
++
Efficient
organisational
structure can be created;
using
expertise
from
established actors further
improving it
+
Rules
for
effective,
reinforeced involvement
+
Efficient because of limited
coordination requirements
Involvement
of
stakeholders
0
Process in the hands of
the main actors
+
Rules
for
effective,
reinforced involvement
Source: European Commission.
The assumptions in this table are based on the feedback received from stakeholders in their response
to the public consultation and from additional submissions from ACER.
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Table 4: Qualitative estimate of the economic impact of the Options
Economic Impact
Internal
Market for
electricity
Option 0:
Business as usual
0/+
Transparency
and
non-
discrimination
-
Administrative
impact
and
implementation
costs
0
Option 1:
Upgrading EU institutional framework
Option 2:
Restructuring EU institutional
framework
+
+
0/-
++
++
--
Source: European Commission
The assumptions in this table are based on the feedback received from stakeholders in their response to the
public consultation and from estimations concerning the resources of ACER and ENTSO-E
.
In summary, Option 0
–
business as usual
–
will fall short in providing for an institutional
framework that can underpin the integration of the internal electricity market in a timely
manner.
Option 1, addressing regulatory gaps by upgrading the EU institutional framework would
be, according to the assessment of the options above, the most appropriate measure for
establishing an EU institutional framework that reflects and complements the increasingly
integrated and regional dimension of the electricity market. This option is favoured by
most of the stakeholders
206
. It represents a flexible approach combining bottom-up
initiatives and top-down steering of the regulatory oversight, respecting the principle of
subsidiarity.
Option 2, significantly restructuring the EU institutional framework, while having
advantages in terms of requiring less coordination and being as efficient as Option 1, it has
the clear disadvantage of requiring significant changes to established institutional practices
and processes and of having the greatest economic impact. Some of the solutions proposed
under Option 2, such as those involving the extension and shifting of decision-making
powers and responsibilities, would raise severe opposition from stakeholders. That would
206
70% of stakeholders responding to the relevant questions of the Commission's public consultation on a
new market design were in favour of strengthening ACER's institutional role, e.g. some mentioning that
it may be efficient to enable ACER to take decisions on cross-border issues where EU network
codes/guidelines require decisions to be taken by all national regulatory authorities. Further, many
stakeholders asked for improving ENTSO-E's independence from its members' commercial interest.
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be for example the case for ACER and the transfer of decision-making powers from
NRAs
207
. In summary, Option 2 did not receive support from stakeholders.
The Commission Services are of the view that Option 1 "upgrading the EU institutional
framework " is currently the most appropriate approach to achieve the main objective
pursued i.e., adapt the institutional framework and ACER's decision powers and internal
decision-making to the reality of integrated regional markets.
It is also relevant to note, that as the institutional framework for the European energy
market design initiative, the proposals discussed above in the options will be accompanied
by some further changes originating from the need to adapt ACER's funding Regulation to
the Common Approach on EU decentralised agencies
208
and to incorporate some minor
improvements to streamline the institutional framework established in the Third Package.
Further, as the Third Package establishes an identical institutional framework for
electricity and for gas
209
, changes to this system will be also applied to the gas sector where
relevant and reasonable to ensure that rules and processes are identical for the two sectors
in the future.
Budgetary implications of improved ACER staffing
This Section provides an estimate of budgetary implications from adjusting ACER staffing
to adequately meet new tasks and responsibilities envisaged under the preferred option
(Option 1) as well as under the highly ambitious Option 2.
As per the Agency's draft 2017 Work Programme, ACER employed on 31.12.2015 a total
of 54 Temporary Agents, of which 39 at AD level and 15 at AST level. The Agency further
employed an additional 20 Contract Agents and 6 SNE, raising the total ACER headcount
to 80.
It should be noted that the European Commission, in its latest opinion on the ACER Work
Programme
210
did not agree to grant additional staff under the 2017 budget, judging that
current staff figures are adequate to meet current tasks and suggesting that ACER shifts
resources internally to meet priority objectives.
207
208
209
210
Most of the Member States responding to the relevant questions of the Commission's public consultation
on a new market design favored preserving the
status quo
as regards the institutional framework.
The Common Approach on EU decentralised agencies agreed in July 2012 by the European Parliament,
the Council and the Commission defines a more coherent and efficient framework for the functioning of
agencies. Although legally non-binding, it serves as a political blueprint not only guiding future
horizontal initiatives but also in reforming existing, individual EU agencies. Most importantly, the
implementation of the Common Approach requires the adaptation of the founding acts of existing
agencies, based on case by case analysis.
For example, the Third Package, in the Gas Regulation established the European Network for
Transmission System Operators for Gas (Art. 5).
Commission Opinion on the draft Work Programme of the Agency for the Cooperation of Energy
Regulators, C(2016)3826 of 24.6.2016
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In line with additional tasks foreseen under Option 1 and Option 2, ACER staffing
resources should however be adapted.
The tables below show the financial implications of Option 1 and Option 2 for extra staff.
The average cost per headcount is based on the latest DG BUDGET declared average
cost
211
: for a Temporary Agent, total average costs including "bailage" costs (real estate
expenses, furniture, IT, etc.), stand at EUR 134.000 per year per individual.
Table 5: ACER staff: budgetary implications under Option 1
Function
(a) No. extra
staff (MIN)
(b) No. extra staff
(MAX)
Budget of (a)
(million euros)
Network Codes and
Regulation
Regulatory
Oversight
Coordination
(Internal and
External)
DSO-related
Total
Budget of (b)
(million euros)
7
12
0.938
1.618
6
10
0.804
1.340
2
3
0.268
0.402
2
+ 17
3
+ 28
0.268
2.278
0.402
3.752
Source: Own calculation based on DG BUDG figures
211
Circular note of DG BUDGET to RUF/2015/34 of 09.12.15
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Table 6: ACER staff: budgetary implications under Option 2
Function
(a) No. extra
staff (MIN)
(b) No. extra staff
(MAX)
Budget of (a)
(million euros)
Network Codes and
Regulation
Regulatory Oversight
Dedicated national
desk offices
Reinforced Board of
Appeal
Coordination
(Internal and
External) &
Management
DSO-related
Total
Budget of (b)
(million euros)
20
30
56
30
35
84
2.680
4.020
7.504
4.020
4.690
11.256
15
20
2.010
2.680
15
20
2.010
2.680
5
+ 141
10
+ 199
0.670
19.296
1.340
26.666
Source: Own calculation based on DG BUDG figures
These calculations are only approximate as they cannot take into account the grade level
of future recruited staff or the exact breakdown of future tasks. This is particularly true for
Option 2, which would entail a complete overhaul of the Agency and the appropriation of
full regulatory competences for 28 markets.
Subsidiarity
The current institutional framework for energy in the Union is based on the
complementarity of regulation at national and EU level. The Third Package mandated the
designation by Member States of national regulatory authorities and required that they
guarantee their independence and ensure that they exercise their role and powers
impartially and transparently at national level. The Third Package also created ACER and
ENTSO-E in order to enhance the coordination of national energy regulators and elecricity
TSOs at EU level.
The implementation of the Third Package through the adoption of Commission
implementing regulations has led to the creation of new entities and functions which have
changed the regulatory landscape. Some of these entities/functions have EU-wide
relevance (e.g., the market coupling operator function in the electricity sector) whereas
others have regional relevance (e.g., the regional security coordinators in the electricity
sector, capacity allocation platforms in the gas sector).
Moreover, the electricity markets have become more integrated due to increasing cross-
border electricity trade and more physical interconnections in the European electricity grid.
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This, together with progressively higher shares of decentralized and variable renewable
energy sources, have rendered the national electricity systems much more interdependent
than in the past.
Whereas the institutional framework envisaged in the Third Package has undoubtedly been
successful, the unprecedented changes described above have highlighted the existence of
regulatory gaps. These gaps appear, for example, where the creation of the
entities/functions with EU-wide or regional relevance has not been accompanied with the
necessary tools to equip ACER with powers to exercise regulatory oversight over them,
despite the fact that they will be carrying out monopoly or critical functions for the internal
energy market at EU or regional level. Other gaps relate to the lack of regulation ensuring
the consistent implementation of governance principles across regions or to the lack of
clarity concerning the roles and responsibilities of national regulatory authorities, ACER
and ENTSO-E following the adoption of Commission implementing regulations.
It is therefore necessary to adapt the institutional framework in the Third Package to meet
this new reality and provide a basis for realizing the full potential of the internal energy
market. This is why the roles of NRAs, ACER, and ENTSO-E need to further evolve,
clarifying their powers and responsibilities over relevant geographical areas. In addition,
it will be necessary to adapt the institutional framework to the changes in EU energy
legislation stemming from the proposed initiatives.
Proportionality
Option 1 would be in line with the proportionality principle given that it aims at clearly
defining the roles, powers and responsibilities of the main actors (NRAs, ACER, ENTSO-
E) so that they are adapted to the new realities of the electricity markets and to the need
for more regional cooperation. More specifically:
-
The improvements to the ACER framework under this option do not aim at
replacing national regulatory authorities but rather at complementing their role as
regards issues which have regional/EU-wide relevance. The scope of ACER's
responsibilities will continue to be limited to cross-border relevant issues.
The improvements concerning the regulatory oversight at regional level aim at
addressing the regulatory gap that has arisen with the implementation of the Third
Package through the adoption of Commission implementing regulations.
The amendments of the ENTSO-E framework under this option principally aim at
improving and clarifying its mandate to ensure its European character and to
introduce more transparency in its internal decision-making processes.
The improvements to the process for developing Commission implementing
regulations (network codes and guidelines) aim at addressing some of the
shortcomings identified in the past years.
The establishment of an EU DSO entity will support EU policies and RES
integration in the electricity system, will support the swift implementation of
network codes and guidelines, and enhance cooperation between TSOs and DSOs.
Stakeholders' opinions
This Section provides a more detailed summary of the views expressed by stakeholders
regarding the adaptation of the institutional framework in the European Electricity
Regulatory Forum and in response to the Commission public consultation on a new market
design.
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The 29
th
meeting of the European Electricity Regulatory Forum of 9 October 2015
underlined, as a conclusion,
"the need for analyzing and further elaborating the roles,
tasks, responsibilities and consider possible governance structures of ACER and ENTSO-
E"
and stressed
"the need to observe and consider possible governance structures for other
bodies, including DSOs and power exchanges, and for NEMO cooperation."
As regards enhancing ACER's institutional role, in response to the Commission public
consultation on a new market design, 70% of all stakeholders who answered the questions
on ACER wanted to increase the powers or tasks of ACER (notably as regards oversight
of ENTSO-E). 30% supported to keep the
status quo.
Only a limited number of respondents
(5%) mentioned missing independence of ACER as a problem. In general, views differed
between Member States and NRAs on the one hand (rather for preserving
status quo)
and
other stakeholders (rather in favour of strengthening powers at regional/EU level).
Within the development of a robust regulatory framework for the entities performing
monopoly or near-monopoly functions at EU or regional level, ACER called for the power
to exercise regulatory oversight over such entities
212
. With regard to regional cooperation,
which should be promoted by the NRAs, ACER can support NRAs' actions and should be
responsible for promoting and monitoring the consistency of regional implementation and
of the activities of entities performing monopoly or near-monopoly activities at regional
level.
As regards ENTSO-E, 38% of the respondents to the public consultation on a new market
design did not have or did not express any opinion or preference regarding the possible
strengthening of ENTSO-E. Looking at the respondents having an opinion on this topic,
59 % of the respondents were in favour of not to strengthen ENTSO-E while 41% asked
for a stronger ENTSO-E.
As regards power exchanges, 63% of the respondents to the consultation answering this
specific question were of the view that there is a need for enhanced regulatory oversight
of power exchanges.
As regards the process for development of Commission implementing regulations in the
form of network codes and guidelines, some of the respondents to the consultation
mentioned the existence of a possible conflict of interest in ENTSO-E’s
role –
being at the
same time an association called to represent the public interest, involved e.g. in network
code drafting, and a lobby organisation with own commercial interests
–
and asked for
measures to address this conflict. Some stakeholders suggested that the process for
developing network codes should be revisited in order to provide a greater a balance of
interests. Some submissions advocated for including DSOs and stakeholders in the
network code drafting process.
As regards DSOs, the establishment of an independent EU-level DSO entity has been
welcomed by stakeholders on multiple occasions. In particular, attention is drawn to the
Conclusions of the 31
st
Energy Regulators Forum, whereby:
"The Forum takes note of the
announcement from the Commission of the establishment of an EU
‐
level DSO entity that
212
ACER's position on the regulatory oversight of (new) entities performing monopoly or near-monopoly
functions at EU-wide or regional level.
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can serve to provide expertise in advancing the EU market. The Forum invites the
Commission, in the design of any entity, to ensure a balanced representation of DSOs and
maximum independence and neutrality".
Equally, regulators (ACER and CEER) suggested
considering whether DSOs should be encouraged to establish a single body through which
they can more efficiently participate in the process of new electricity market design.
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