Europaudvalget 2016
KOM (2016) 0864
Offentligt
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EUROPEAN
COMMISSION
Brussels, 30.11.2016
SWD(2016) 410 final
PART 4/5
COMMISSION STAFF WORKING DOCUMENT
IMPACT ASSESSMENT
Accompanying the document
Proposal for a Directive of the European Parliament and of the Council on common
rules for the internal market in electricity (recast)
Proposal for a Regulation of the European Parliament and of the Council on the
electricity market (recast)
Proposal for a Regulation of the European Parliament and of the Council establishing
a European Union Agency for the Cooperation of Energy Regulators (recast)
Proposal for a Regulation of the European Parliament and of the Council on risk
preparedness in the electricity sector
{COM(2016) 861 final}
{SWD(2016) 411 final}
{SWD(2016) 412 final}
{SWD(2016) 413 final}
EN
EN
kom (2016) 0864 - Ingen titel
TABLE OF CONTENTS
4. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA II, OPTION 2(1);
(IMPROVED ENERGY MARKETS, NO CMS) .................................................................. 209
4.1. Removing price caps ................................................................................................................... 209
4.1.1. Summary table ............................................................................................................................. 209
4.1.2. Description of the baseline .......................................................................................................... 210
4.1.3. Deficiencies of the current legislation ......................................................................................... 215
4.1.4. Presentation of the options ......................................................................................................... 216
4.1.5. Comparison of the options .......................................................................................................... 216
4.1.6. Subsidiarity................................................................................................................................... 218
4.1.7. Stakeholders' opinions ................................................................................................................. 218
4.2. Improving locational price signals ............................................................................................... 220
4.2.1. Summary Table ............................................................................................................................ 221
4.2.2. Description of the baseline .......................................................................................................... 222
4.2.3. Deficiencies of the current legislation ......................................................................................... 228
4.2.4. Presentation of the options ......................................................................................................... 229
4.2.5. Comparison of the options .......................................................................................................... 230
4.2.6. Subsidiarity................................................................................................................................... 231
4.2.7. Stakeholders' opinions ................................................................................................................. 232
4.3. Minimise investment and dispatch distortions due to transmission tariff structures .................... 234
4.3.1. Summary table ............................................................................................................................. 235
4.3.2. Description of the baseline .......................................................................................................... 236
4.3.3. Deficiencies of the current legislation ......................................................................................... 238
4.3.4. Presentation of the options ......................................................................................................... 239
4.3.5. Comparison of the options .......................................................................................................... 240
4.3.6. Subsidiarity................................................................................................................................... 245
4.3.7. Stakeholders' opinions ................................................................................................................. 245
4.4. Congestion income spending to increase cross-border capacity ................................................... 248
4.4.1. Summary table ............................................................................................................................. 249
4.4.2. Description of the baseline .......................................................................................................... 251
4.4.3. Deficiencies of the current legislation ......................................................................................... 254
4.4.4. Presentation of new measures/options ...................................................................................... 255
4.4.5. Comparison of the options .......................................................................................................... 257
4.4.6. Subsidiarity................................................................................................................................... 259
4.4.7. Stakeholders' opinions ................................................................................................................. 260
5. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA II, OPTION 2(2)
(IMPROVED ENERGY MARKETS - CMS ONLY WHEN NEEDED, BASED ON
COMMON EU-WIDE ADEQUACY ASSESSMENT ( AND OPTION 2(3) (IMPROVED
ENERGY MARKET, CMS ONLY WHEN NEEDED BASED ON COMMON EU-WIDE
ADEQUACY ASSESSMENT, PLUS CROSS-BORDER PARTICIPATION) ................. 262
5.1. Improved resource adequacy methodology ................................................................................ 264
5.1.1. Summary table ............................................................................................................................. 265
5.1.2. Description of the baseline .......................................................................................................... 266
5.1.3. Deficiencies of the current legislation ......................................................................................... 272
5.1.4. Presentation of the options ......................................................................................................... 273
5.1.5. Comparison of the options .......................................................................................................... 275
5.1.6. Subsidiarity................................................................................................................................... 283
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5.1.7. Stakeholders' opinions ................................................................................................................. 283
5.2. Cross-border operation of capacity mechanisms ......................................................................... 286
5.2.1. Summary table ............................................................................................................................. 287
5.2.2. Description of the baseline .......................................................................................................... 288
5.2.3. Deficiencies of the current legislation ......................................................................................... 289
5.2.4. Presentation of the options ......................................................................................................... 290
5.2.5. Comparison of the options .......................................................................................................... 293
5.2.6. Subsidiarity................................................................................................................................... 296
5.2.7. Stakeholders' opinions ................................................................................................................. 296
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4. D
ETAILED MEASURES ASSESSED UNDER
P
ROBLEM
A
REA
II,
OPTION
2(1);
(
IMPROVED
E
NERGY
M
ARKETS
,
NO
CM
S
)
4.1. Removing price caps
4.1.1.
Summary table
Objective: to ensure that prices in wholesale markets and not prevented from reflecting scarcity and the value that society places on energy.
Option 0: Business as usual
Existing regulations already require harmonisation of
maximum (and minimum) clearing prices in all price
zones to a level which takes "into account an estimation
of the value of lost load".
Non-regulatory approach
Enforceability of
"into account an estimation of the
value of lost load"
in the CACM Guideline is not strong.
Enforcement action is unlikely to be successful or
expedient. Relying on stronger enforcement would leave
considerable more legal uncertainty to market
participants than clarifying the legal framework
directly.Voluntary cooperation not provide the market
with sufficient confidence that governments would not
step in restrict prices in the event of scarcity.
Simple to implement
leaves adminstration to technical
implementation of the CACM Guideline.
Difficult to enforce; no clarity on how such clearing
prices will be harmonised. Does not prevent price caps
being implemented by other means.
Cons
Option 1: Eliminate all price caps
Eliminate price caps altogether for
balancing, intraday and day-ahead markets
Removes barriers for scarcity pricing
Avoids setting of VoLL (for the purpose of
removing negative effects of price caps)
Option 2: Create obligation to set price caps, where they exist, at VoLL
Reinforced requirement to set price limits taking "into account an estimation of
the value of lost load"
Allow for technical price limits as part of market coupling, provided they do not
prevent prices rising to VoLL.
Establish requirements to minimise implicit price caps.
Description
Pros
Measure
simple
to
implement;
unequivocally and creates legal certainty.
Can be considered as non-proportional;
could add risk to market participants and
power exchanges if there are no limits .
Compatible with already existing requirement to set price limit, as provided for
undert the CACM regulation, provides concrete legal clarity
VoLL, whilst a useful concept, is difficult to set in practice. A multitude of
approaches exist.
Most suitable Option(s): Option 2
- this provides a proportionate response to the issue
–,
it would allow for technical limits as part of market coupling and this should not restrict the markets
ability to generate prices that reflect scarcity.
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4.1.2.
Description of the baseline
Scarcity pricing is critical to investment in flexible generation and demand. Traditionally,
power plants have been built based on receiving a stable revenue and operating with high
levels of output for a significant proportion of time (i.e. high load factors). However,
with more variable renewable technologies entering on to the system, with generally very
low or zero marginal costs, the patterns that more conventional forms of generation
operate (e.g. gas) is changing. Investment will no longer be able to take place based on
the assumption that plants will operate at high load factors for a significant portion of
their working life; with more and more generation from renewables, with lower running
costs, these plants will operate less and less. However, they will remain critical in
providing a stable electricity system. They will need to operate to keep supply steady in
times of low renewable generation and flexibility will be key. There will be more and
more occasions when prices could reach very high levels (in times of scarcity) but for
very short periods of time. It is these peaking prices that can provide the signals and
stimulate the investment needed in flexible capacity so long as investors have the
confidence that they will be able to recoup their money based on such prices. Further,
such prices are critical in stimulating other forms of flexibility, notably in the form of
demand response
in the case where a consumer (industrial or residential) has a contract
which reflects wholesale price movements, the greater the price differences, the greater
the incentive to respond by reducing consumption and instead using energy at lower price
periods.
It is not the case, however, that all consumers will necessarily see such short-term
changes in prices. In general, consumers will be more affected by the longer-term
changes in average prices; these will more likely feed through to energy bills for reasons
explained below.
Whilst different formulas exist, unit costs in a standard fixed or variable (monthly) retail
tariff will be an average of the wholesale price over a period of time, with additional
costs added, such as network costs, taxes, etc., along with any supplier margins.
Consumers on these tariffs will be shielded from period-by-period changes in the
wholesale price, be they up or down.
Whilst the development of demand response will be enhanced by dynamic tariffs which
better reflect the wholesale price, there is no proposal for this to be obligatory. If a
consumer were to choose a tariff that mirrored the wholesale price on a 1:1 ratio,
overtime they would likely pay less as their suppliers would face lower hedging costs,
which they could then pass on to those consumers as tariff savings (lower margins). This
is illustrated in the Nordic markets, where hourly tariffs are often the cheapest on the
market for most consumers. Nevertheless, consumers whose peak consumption
consistently coincided with price peaks on the market, and who chose a dynamic tariff,
may end up paying more at the end of the billing period, reflecting their cost to the
system.
The formation of scarcity prices can be contained directly or indirectly and, in particular,
by caps on prices. These can be implemented for a number of reasons, including
technical (e.g. required as part of the operation of the programs which determine market
results), to improve the robustness of market operation (e.g. to prevent significant errors
in bidding affecting market outcomes), for competition reasons (i.e. to limit any abuse of
a dominant position), for consumer-related reasons (e.g. to limit consumer exposure to
high prices) and for financial reasons (e.g. to limit the collateral needing to be posted).
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In a perfect market, supply and demand will reach an equilibrium where the wholesale
price reflects the marginal cost of supply for generators and the marginal willingness to
pay for consumers. If generation capacity is scarce, the market price should reflect the
marginal willingness to pay for increased consumption. As most consumers do not
participate directly into the wholesale market, the estimated marginal value of
consumption is based on the value of lost load (VoLL). VoLL is a projected value which
is supposed to reflect the maximum price consumers are willing to pay to be supplied
with electricity. If the wholesale price exceeds the VoLL, consumers would prefer to
reduce their consumption, i.e. be curtailed. If, however the wholesale price is lower than
the VoLL, consumers would rather pay the wholesale price and receive electricity. If
prices are prevented from reaching the VoLL through the introduction of price caps, then
short-term prices will be too low in scarcity situations. This in turn can affect investment
signals - notably, it can reduce the incentive to investment in flexible capacity (i.e. of the
type that can respond to short-term peaks in prices) and demand response.
However, currently all Member States have specific restrictions on the price to which
wholesale prices can rise. In the day-ahead market, the most common cap is EUR
3000/MWh, which is by-and-large a technical constraint rather than implemented with
the intention of keeping prices below VoLL. Some Member States have values somewhat
lower, which could introduce distortions in the price signals.
Figure 1
Day-ahead price caps
Majority: +3000 EUR/MWh
GB: +3000 or +6000 GBP/MWh
Greece: 150 EUR/MWh
Ireland: +1000 EUR/MWh
Poland: 347 EUR/MWh, +3000
EUR/MWh (x-border)
Portugal/Spain: 180 EUR/MWh
Source: "Market design: Barriers to optimal investment decisions"
Impact Assessment support study,
(2016) COWI
These values have limited relationship to the value of lost load and, therefore, if
maintained would prevent prices rising to the level to which society values energy. For
example, a recent study commissioned for the UK's Department of Energy and Climate
Change estimated that VoLL for Electricity in Great Britain to be GBP 10,289/MWh for
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domestic users and GBP 35,488 for SMEs on a winter peak workday (approximately
EUR 13,500/MWh and EUR 46,500/MWh at the time of writing)
1
. Whilst VoLL will
change depending on the circumstances, the user and the location (it will not be the same
in all Member States), it is clearly much higher than the limits that currently exist in
many day-ahead markets. Price caps in the intraday markets show a lot less
harmonisation - see map below. Whilst the level is generally much higher - i.e. no caps in
some countries, and up to EUR 9999,99/MWh in others, and therefore are less likely to
create distortions, some Member States have price caps which will fall far below VoLL.
Figure 2
Intraday price caps
Green: No ID market
Light blue: -9999,99 to +9999,99
EUR/MWh
-
Stripes: DE: Discrete -
3000/+3000 EUR/MWh
Dark blue: No price caps
Czech: +3700 EUR/MWh
Dark red:
-
-
-
GB: 0/+2000 GBP/MWh
IT: 0/+3000 EUR/MWh
PT, ES: 0/+180 EUR/MWh
Source: "Market design: Barriers to optimal investment decisions"
Impact Assessment support study,
(2016) COWI
With regards to the balancing timeframe, price caps apply to the activation (energy) part
of balancing services in several Member States. In some countries there are fixed price
caps, like +/-9999,99 EUR/MWh in Slovenia, +/-3700 EUR/MWh in Czech Republic, or
203 EUR/MWh for FRR in Lithuania. In Austria and the Nordic countries, the floor
price is equal to the day-ahead price, meaning that there is a guarantee that the payment
for energy injected for balancing is at least equal to the day ahead price. In Belgium,
1
https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/224028/value_lost_load
_electricty_gb.pdf
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FRR prices are capped to zero (downward regulation) and to the fuel cost of CCGT plus
40 euros (upward regulation). Most Member States do not have price caps for capacity
(reserve) bids.
There is an important relationship between the price paid for balancing services and the
imbalance price
that is, the price determined by TSOs which producers and consumers
must pay as they use or produce too much or too little energy compared to their
contracted amount. As detailed further below, it is this real-time price which will have
the biggest impact on prices in the intraday, day-ahead and forward prices. However, it
will be heavily influenced by the price that TSOs pay for balancing services. In
particular, under the upcoming Balancing Guideline, there are restrictions on how it can
be formed based on the price paid for activation of balancing energy. The Guideline will
also require that there are no caps or floors to balancing energy prices.
Free formation of prices in the balancing market is perhaps the most important issue;
day-ahead and intraday markets effectively act as an opportunity to hedge against the
expected imbalance price - they will not buy or sell energy above this price as it will be
cheaper to be out of balance and pay the imbalance price. Therefore, the balancing price
should not mute scarcity pricing by capping prices below VoLL, else prices in the
intraday and day-ahead timeframes will not reflect scarcity, regardless of any caps put in
place.
The following diagrams illustrate the relationship between prices in each of the three
market timeframes, using the example of the imbalance price in Belgium on the 22nd
September 2015. Figure 5 shows a high imbalance price caused by scarcity due to
unplanned outages.
Figure 3
Day-ahead spot prices as a result from the matching of orders in and the
coupling of the bidding zones in the CWE-region on the 21
st
, 22
nd
and 23
rd
September 2015
Source: Belpex, EEX, APX
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Figure 4
Intraday prices in Belgium on 21
st
, 22
nd
and 23
rd
September 2015
Source: Belpex
Figure 5
Imbalance prices in Belgium on 21
st
, 22
nd
and 23
rd
September 2015,
Source: Elia
From these, it can be seen that the market is behaving rationally - i.e. that parties are
trading in the day-ahead and intraday markets to hedge themselves. The prices are
tracking the imbalance price. If it was prevented from going above a set amount, this
would have an effect on bidding behaviour in the other two timeframes, which would
also not go above this price. As the imbalance price will change in real time, market
participants can only base their bidding in the day ahead and intraday markets based on
what they expect the price will be. Therefore, such tracking of prices across timeframes
will not happen where there are very short-term changes in the imbalance price, e.g. due
to sudden tripping of equipment.
It should be noted that there is a difference between price restrictions on the price paid
for activation of energy by TSOs in the balancing timeframe, and the imbalance price.
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The former will help inform the imbalance price, but it is generally the latter that has the
most impact on behaviour in the day-ahead and intraday market.
Two issues exist relating to harmonisation of caps. Firstly, given the above, that of
harmonisation between timeframes. If caps exist in the balancing timeframe, there is little
point in having a cap higher than this in intraday or day ahead, as there will be no reason
for market parties to bid or offer energy at a higher price - i.e. because it will be cheaper
to pay the imbalance price. It is therefore important that there is consistency across
market timeframes. The second issue relates to harmonisation between markets. If there
are different price caps each side of a border, this can interfere with how energy flows in
times of system stress. Take for example Member State A with a price cap of 1000, on a
border with a Member States B whose price cap is 100. In the absence of a cap, energy
would flow to the country who valued it the most, i.e. with the higher price. However,
with these caps if there was a concurrent scarcity event which led to prices going above
100, then energy will always flow to Member State A, despite the fact that Member State
B might value energy as much or more (i.e. because the price cannot attract flows of
energy more than Member State A’s prices).
Implicit price caps can also exist. For example, in some Member States (around a third),
a shadow auction
2
is triggered if prices reach 500 euros /MWh (or goes below -150 euros
/MWh). This can act as a disincentive to bid higher than EUR 500 . Other disincentives
that have been identified include: general fears about competition law
for example, the
market restricting itself out of fear of being seen to be abusing a dominant position; the
price at which strategic reserves are activated; and TSO actions based on market price.
4.1.3.
Deficiencies of the current legislation
Current European legislation contains very little reference to wholesale market prices
caps. In fact, the only reference is contained in the CACM Guideline. Specifically,
Articles 54 (covering intraday trading) and Article 41 (covering day-ahead) require
power exchanges, acting in their cross-border roles as NEMOs to propose harmonised
maximum and minimum bid prices. This needs to "take into account the value of lost
load." This proposal is due to be made to regulatory authorities by mid May 2017.
As pointed out in the Evaluation Report, normally, well-functioning wholesale markets
should provide price signals necessary to trigger the right investment. However, the
ability of markets to do so is debated today because today's electricity markets are
characterised by uncertainties as well as by a number of market and regulatory failures
which affect price signals. These include low price caps, renewable support schemes, the
lack of short term markets and lack of demand response operators.
2
Auctions run to validate that the results of the first auction are correct and not abnormal prices due to
either technical issues during the execution of the market clearing algorithms, or bidding behaviour of
market participants.
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4.1.4.
Presentation of the options
Option 0: Business as usual
The option would allow for the continuation of limits on wholesale prices. This would in
principle allow for different price caps in different timeframes. However, under the terms
of the CACM Guideline it would bring harmonisation in day-ahead and intraday as there
is a requirement for a harmonised value in all bidding zones participating in market
coupling. This value would have to "take into account" the value of lost load. It would
not, however, have to represent this value and could be significantly lower. For example,
as part of the NWE market coupling project, there is a maximum clearing price of
3000euros/MWh in those bidding zones taking part in the project. This limit has been
applied to other markets, for example the German intraday auction (which takes place
after the cross-border auction) and the GB day-ahead auction (a similar process, again
after the cross-border auction, although the limit is expressed in GBP). This is most
likely due to issues of convenience and to prevent creating perverse incentives to trade in
one of the markets as opposed to another.
Option 1: Eliminate all price caps
This option would see a prohibition on all upper price restrictions in the wholesale
market, in all timeframes. It would mean that prices would be able to reach VoLL. It
would also involve a prohibition on any technical price limits imposed by power
exchanges.
Option 2: Create obligation to set price caps, where they exist, at VoLL
This option would require that, where caps exist, they shall be no lower than VoLL in all
market timeframes. This would be coupled with a requirement that Member States
establish VoLL. This option would be compatible with a technical limit imposed by
power exchanges, but would include a trigger to raise such limits in order to prevent
them constraining acurate price formation coupled with a date by which the maximum
must not be below VoLL. It would also make clear that, once at VoLL, the value need
not be harmonised.
4.1.5.
Comparison of the options
As detailed above, allowing prices to reflect scarcity, and investors having confidence
that this will be allowed to happen, is key to stimulating investment in a more flexible
system.
The options must, therefore, be assessed in this context i.e. those options which would
prevent scarcity prices forming and, in particular, reflecting the true scarcity in terms of
willingness to pay for energy, would not be compatible with the objective of creating an
energy market that is able to face future challenges and stimulate the right investments.
The 'do nothing' option would not be consistent with the set objectives
even though
harmonised maximum clearing prices would be implemented, these only have to 'take
into account' the value of lost load and there would be no way to provide confidence that
prices could indeed reach values which reflect scarcity. It would allow for price caps to
continue existing within Member States. Whilst in practice, for most Member States,
prices have not been constrained by existing caps (there have been no instances yet
where they have hit the 3000 euros mark), this is not set to remain the case forever.
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Doing nothing, or relying on voluntary cooperation at the Member State level, would not
provide investors with any confidence that restrictions would be removed (or raised) in
the event they were hit and the default position is that they would remain in place. It
therefore has to be assumed that such an option would shave off the peaks in pricing.
Whilst the CACM Guideline contains a reference to VoLL, ‘take into account' is not
enforceable.
Option 1
to eliminate any price caps - would be the option most in line with this
specific objective, in that it would allow prices to rise to any level, determined by supply
and demand fundamentals. Making a strict, EU-level prohibition may provide investors
with confidence that Member States would not intervene to keep wholesale prices low for
political reasons
e.g. because of a negative perception of the impacts of peaking prices
on consumers. This option, however, entails risks. In particular, it would prevent any
limits being used in the market coupling system or by power exchanges. This could have
technical impact on the operation of the systems used to run the markets and may
influence the amount of collateral that market parties are required to post. Market parties
are generally required to provide cash or credit to cover their potential exposure. Without
limits in the clearing price, this could become more expensive or their credit more
restrictive (e.g. on how much they can trade), as the potential exposure would be higher.
Further, it could prevent the use of any explict price-based measure to detect errors in
bidding.
Option 2 would allow for the use of limits to exist in the context of trading on the power
exchanges and only in relation to maximum and minimum clearing prices developed in
accordance with the CACM Guideline. In order to prevent such limits restricting accurate
price formation, the option would also introduce a specific requirement that they be
raised when a trigger point is reached coupled with a requirement that they be set at the
value of lost load within a certain timeframe. The option would also prohibit Member
States from introducing legal caps on the wholesale price unless this reflects a calculation
of the value of lost load.
The advantage of this approach is that it would still allow for technical limits to be
introduced by power exchanges, but would not constrain price formation and would give
investors a clear signal that Member State authorities cannot step in artificially dampen
prices. The disadvantage as compared to Option 1 is that, in order for such limits to
continue to exist and to be effective, there may need to be a time lag between the trigger
and the limit being raised. This would need to be as short as possible so not to prevent
prices from rising.
A difficulty with this option is the complexity of establishing VoLL. It will change
depending on the circumstances and the user and so one value will only ever be an
estimation.
This option would also be bundled with a requirement placed on Member States to avoid
and, where possible, eliminate any implicit price caps so not to disincentives the offering
of high prices by market participants.
The benefits of better price signals and further articulated as part of the wider option to
address uncertainty on future investments (Problem Area II, which includes policies on
locational signals, scarcity pricing and price caps, resource adequacy planning and
capacity mechanisms) in Section 6.2.2.
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4.1.6.
Subsidiarity
Given that the EU energy system is highly integrated, prices in one country can have a
significant effect on prices in another. Further, if there are significant differences
between countries on the level to which wholesale prices can rise, then energy may flow
in the wrong direction during times of system stress. A coordinated and harmonised
approach is, therefore, necessary.
This topic is, to an extent, already covered under the CACM Guideline
which notably
requires the setting of harmonised maximum clearing prices which take into account the
value of lost load.
Differences in national approaches could create significant distortions in the market and
prevent the most cost-effective supply of electricity. It could also distort investment
signals, for example those countries who have a higher cap would potentially attract
more investment thnt those with a lower cap.
EU action is therefore necessary to ensure a common approach is taken which minimises
distortions in the operation of markets between Member States.
4.1.7.
Stakeholders' opinions
From the Market Design consultation, a large majority of stakeholders agreed that
scarcity pricing is an important element in the future market design. It is perceived, along
with current development of hedging products, as a way to enhance competitiveness.
While single answers point at risks of more volatile pricing and price peaks (e.g. political
acceptance, abuse of market power), others stress that those respective risks can be
avoided (e.g. by hedging against volatility).
Many submissions to the consultation highlighted the link between scarcity pricing and
incentives for investments/capacity remuneration mechanisms, as well as the crucial role
of scarcity pricing for kick-starting demand response at industrial and household level.
Key stakeholder comments included:
-
"…energy prices that reflect market fundamentals, including scarcity in terms of
time and location, are an important ingredient of the electricity market design.
Undistorted prices (without regulatory intervention) should thus trigger optimal
dispatch and signal the need for investments/divestments… Price caps and other
interventions in the market hindering the appearance of scarcity prices should be
removed."
Eurelectric
"…we need to better valorize flexibility.
Prices reflecting scarcity are crucial in
this context and should therefore be a key priority of the market reform…
Prices
better reflecting scarcity will be more volatile and might be higher than today
during some periods of the day (assuming the end of price caps). Rather than a
challenge, this represents an opportunity as it will unlock new strategies to hedge
against risks on the wholesale market while triggering dynamic pricing offers on
the retail side."
SolarPower Europe.
"In principle, electricity prices should reflect actual scarcity so that the most
cost-efficient flexibility options on the supply and the demand side as well as the
most efficient storage solutions are employed. Prices should also reflect the
scarcity of transmission capacities within and across market borders"
EUROCHAMBERS
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-
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-
-
-
"In order to provide correct price signals for new investments (both generation
and consumption), and to provide security of supply, prices which reflect actual
scarcity are an important ingredient in the future market design."
BusinessEurope
"Citizens Advice supports efforts to move to market structures that more
accurately reflect scarcity. This is an important way of conveying price signals
reflecting the genuine value of consumption and production, at different times
and in different locations."
Citizens Advice
"…energy prices should effectively reflect both temporal scarcity and surplus in
order to adequately reward flexibility. Such an approach to energy pricing would
better facilitate the investments required to address the European energy
trilemma of sustainability, security of supplies, and competitiveness."
WWF
Further, in a position paper, Wind Europe state that "[i]t
is important that market prices
are undistorted and allowed to move freely without caps. Transparent market prices must
be in place in all time horizons, i.e. forward, day-ahead, intraday and real time, and also
used for settlement of remaining imbalances. This will help to incentivise and reward the
provision of flexibility services. Policy makers should be aware that price spikes are
needed to trigger the right scarcity signals on both the supply and demand side;
investment decisions based on a certain expectation of price spikes will only be made if
there is enough trust by investors that politicians will not interfere and introduce price
caps. "
3
The March 2016 Florence Forum made the following relevant conclusion:
"The Forum acknowledges the significant progress being made on the integration of
cross-border markets in the intraday and day-ahead timeframes, and considers that
market coupling should be the foundation for such markets. Nevertheless, the Forum
recognises that barriers may continue to exist to the creation of prices that reflect
scarcity and invites the Commission, as part of the energy market design initiative, to
identify measures needed to overcome such barriers. In doing so, it requests the
Commission take proper account of technical constraints that may exist."
3
https://windeurope.org/fileadmin/files/library/publications/position-papers/EWEA-Position-Paper-
Market-Design.pdf
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4.2.1.
Summary Table
Objective: The objective is to have in place a robust process for deciding on the structure of locational price signals for investment and dispatch decisions in the EU electricity
wholesale market.
Option 0
Option 1
Option 2
Option 3
Business as Usual
decision on bidding
zone configuration left to the arrangements
defined under the CACM Guideline or
voluntary cooperation, which has, to date,
retained the
status quo.
Move to a nodal pricing system
Introduce locational signals by new means,
i.e. through transmission tariffs
Improve currently existing the CACM
Guideline procedure for reviewing bidding
zones and introducing supranational
decision-making, e.g. through ACER.
This would be coupled with a strengthened
requirement to avoid the reduction of cross-
zonal capcity in order to resolve internal
congestions.
This improvement will render revisions of
bidding zones a more technical decision.
It will also increase the available cross-
zonal capacity.
Does not address a situation where the
results of the bidding zone review are sub-
optimal. I.e. this option only covers
procedural issues.
Description
Approach already agreed.
Theoretically, nodal pricing is the most
optimal pricing system for electricity
markets and networks.
Would unlock alternative means to provide
locational signals for investment and
dispatch decisions.
Pros
Risks maintenance of the
status quo,
and
therefore misses the opportunity to address
issues in the internal market.
Incentives would be not be the result of
market signals (value of electricity) but cost
components set by regulatory intervention
of a potentially highly political nature.
Does not address the underlying difficulty
of introducing locational price zones,
namely the difficulties to arrive at decisions
that reflect congestion instead of political
borders.
Most suitable option(s): Option 3
this option will rely on a pre-established process but improve the decision-making so that decisions take into account cross-border impact of bidding zone
configuration. Other options
e.g. tofundementally change how locational signals are provided, would be dispropritionate.
Cons
Nodal pricing implies a complete,
fundamental overhaul of current grid
management and electricity trading
arrangements
with
very
substantial
transition costs.
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4.2.2.
Description of the baseline
The internal energy market is based on the concept of bidding zones, which are defined
as
"the largest geographical area within which market participants are able to exchange
energy without capacity allocation."
4
They are effectively market areas within which
energy is considered to be able to flow freely and within which, therefore, there will be a
single wholesale price for any given market timeframe.
Currently, bidding zones are based on national borders, although there are some
exceptions
5
.
Figure 1, Curent bidding zone configuration
Source: Ofgem, 2014
The wholesale price will be the same in one part of France as it is in another, the same in
one part of Spain as it is another part of Spain, the same in Germany as it is in
Luxembourg and Austria, and so on. The wholesale price in Italy may be different in
different parts, as it may be in Sweden and Norway.
4
5
Commission Regulation (EU) No 543/2013 of 14 June 2013 on submission and publication of data in
electricity markets
There is currently one German-Austrian-Luxembourg bidding zone, and Italy, Sweden and Norway
are split into several zones.
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This is critical, as the wholesale price is a crucial part of determining when and where
people invest (and where there are no other revenue streams such as capacity
mechanisms, the only basis). Higher prices in one area will in theory attract investment
into that area over and above somewhere with lower prices. This locational signal in the
energy price will not exist within a bidding zone, and so will not encourage investment in
one part as compared to another and, in the case where bidding zone boundaries are
based on Member State borders, within one part of a Member State compared to another.
This is despite the fact that there may be bottlenecks within that Member State that
prevent the free flow of energy from one part to another and, hence, could create a
greater need for investment in certain geographical areas.
Further, wholesale energy prices will determine when generating plants dispatch and, to a
lesser degree (due to relative inelasticity in the demand-side) when load consumes
energy. i.e. where the price is higher than a generator's short-run marginal cost, bar any
external factors, they will run. If there are significant congestions within a bidding zone,
and the price is influenced by demand behind such congestion, generators on the other
side may still dispatch despite limited ability to transport the energy to the demand. This
can result in the so-called 'loop flow' phenomenon whereby energy will flow around the
congestions through another zone, against market price signals. These flows, as they have
not been scheduled, can have significant implications. More specifically, they can reduce
the amount of cross-border capacity made available to the market for trade and result in
costly remedial actions, for example the need to redispatch (the reduction in the amount
of power injected on one side of the congestion and, simultaneously, an equivalent
increase in the amount injected on the other side). As an example, in 2015 the total cost
for redispatching within the DE-AT-LU bidding zone was approximately 930 million
euros
6
. Overall, the total welfare loss due to loop flows was estimated to be around 450
million euros in 2014
7
.
An improved configuration of bidding zones, one which takes account of structural
congestions within the European grid, would mitigate many of these issues, as it would
improve the locational price signals. In particular, in the short-term it would affect how
and where energy is dispatched and, for the longer-term, will improve the price signals
on where to locate new generation investments. Clearly investment in transmission
capacity is also critical, notably within a bidding zone so that energy can better flow from
one area to another. However, the bidding zone structure itself may not provide strong
signals for such investment; as Ofgem point out in its Bidding Zone Literature Review
(2014)
8
, impact on investment may be muted by practical consideration, for example, due
to economies of scale, uncertainties about future generation investment, and difficulty in
centralising charges or reliability and quality of service.
6
7
ENTSO-E Transparency Platform, at
https://transparency.entsoe.eu/
"Market
Monitoring Report 2014"
(2015) ACER
social welfare losses for both unscheduled flows
and unscheduled allocated flows.
https://www.ofgem.gov.uk/sites/default/files/docs/2014/10/fta_bidding_zone_configuration_literature_
review_1.pdf
8
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The precise definition of bidding zones, and realising maximum benefit from it, is
complex and highly technical, and there are a number of variables which must be
considered. Therefore, a review process, to be undertaken by TSOs, has been formalised
in legislation under the CACM Guideline
9
. More specifically, once a review is
launched
10
, TSOs are to review the existing bidding zone configuration and alternative
bidding zone configurations, and must submit this to Member States or, where so
determined by a Member State, NRAs for a decision on whether to amend or maintain
the zones. Figure 2 below provides a summary of this process.
Figure 2, simplified flow chart of bidding zone review process under the CACM
Guideline
ACER
NRAs
One NRA
Launch Review
TSOs
MS
TSOs: Develop methodology and assumptions
NRAs
MS (or
NRA)
TSOs: Assess and compare, consult and submit proposal
MS/NRAs: Reach agreement on proposal to maintain or amend
When undertaking a review, TSOs must consider issues relating to network security,
market efficiency, including any increase or decrease in economic efficiency of changes,
and stability and robustness of bidding zones.
A number of authors have already suggested alternative configurations, for example as
shown in figure 3.
9
10
In practice, work has already started on this.
Which can be done by ACER, NRAs, Member States or TSOs, depending on specific criteria
Article
32
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Figure 3, possible alternative configuration,
Source: Supponen, Influence of National and Company Interests on European Electricity Transmission
Investments, 2011
However, as pointed out by Supponen (2011), even price zones which reflect the most
congested parts of the European grid, will not provide as efficient price signals as a
system which is based on a more granular system, such as that of nodal pricing. Nodal
pricing is a method of determining prices in which market clearing prices are calculated
for a number of locations on the transmission grid called 'nodes'. These nodes would be
determined based on the most congested points in the system. The price at each node
represents the locational value of energy, which includes the cost of the energy and the
cost of delivering it
11
. This model is used in much of North America. For example, the
PJM’s system includes over 10 000 price nodes across 20 transmission control zones,
with trading available at nodes, at aggregates of several nodes, at 12 hubs consisting of
hundreds of nodes each, and at 17 import and export external interfaces. The IEA
conclude that
"This nodal pricing system facilitates adjustments to dispatch in the real-
time market, efficient use of variable resources and demand-side response, and limits to
market power by individual generators"
12
.
In 2014, Breuer simulated the potential price differences based on a nodal system in
Europe, comparing average across the year with times of strong wind and high load in
continental Europe.
11
12
Phillips, Nodal Pricing Basics, Independent Electricity Market Operator,
http://www.ieso.ca/imoweb/pubs/consult/mep/LMP_NodalBasics_2004jan14.pdf
Repowering markets
available
at
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Figure 4
Nodal prices, base case (2016)
Source: Breuer, Optimised bidding area delineations and their evaluation in the European Electricity
System, Brussels, April 2014
Nodal prices (base case) 2016
As can be seen from the above, there could be significant changes in prices in a nodal
system compared to average prices across Europe on windy days with high demand.
Such a picture serves to illustrate what the prices should be if transmission capacity were
fully taken into account. This does not cluster around the current bidding zone
configuration as shown above and suggests inaccuracy of price formation in the current
setup. It is also far from clear just from the above how this could be best grouped into a
bidding zone structure, and several possibilities exist just from this one scenario. The
complexity could be further increased when looking at alternative scenarios (e.g. high
wind/low demand, etc.).
It is therefore concluded that it is correct to rely on a technical analysis where the costs,
benefits and practical considerations (including those listed in the CACM Guideline) will
be considered
this is much more likely to result in a more optimal configuration than
the one currently seen. The issue at stake, therefore, is how to make any change based on
the outcome of the review pre-establishing under the CACM Guideline, or whether to
move to a wholly different arrangement for locational signals such as the mandatory
introduction of locational elements in transmission changes or moving to a nodal system
Cross-zonal capacity calculation
With a, theoretical, 'perfect' bidding zone configuration, the only congestion would be on
a bidding zone border. Therefore, there would be no internal constraints that would cause
reductions in cross-border capacity. However, even if and when a configuration is
implemented that better reflects structural congestion, there will still be internal
congestion. The Electricity Regulation states that:
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"TSOs shall not limit interconnection capacity in order to solve congestion inside
their own control area, save for the abovementioned reasons and reasons of
operational security"
13
There is, however, evidence that cross-zonal (interconnection) capacity is indeed being
limited in order to deal with internal issues. In its Market Monitoring Report, ACER
analysed the ratio between thermal capacity (the theoretical maximum capacity) of
interconnectors and the capacity offered for trade (with Net Available Capacity
NTC
Capacity). The results showed that the ratios varied significantly and that on a number of
borders the NTC was significantly below the thermal capacity.
Figure 5
Ratio between available NRC and aggregated thermal capacity of
interconnectors
2014 (%, MW),
Source: ACER/CEER Market Monitoring Report 2015.
ACER concluded that "these results indicate that on the borders on the right side of the
figure either the internal congestions are shifted to the border, or those borders are
affected by a significant amount of unscheduled flows."
Regardless of the reason, the impact of this is the reduction of cross-border trade and has
resulted in the need to curtail capacity the other side of the border. The German-Danish
border provides an example of the sorts of impacts this can have. The below graph shows
the average interconnection capacity was 250MW on DK1-DE in 2015, 15% of the
maximum capacity. An investigation for the Danish TSO energinet.dk and the relevant
13
Annex I section 1.7
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German TSO TenneT found that a minimum capacity of 1.000 MW will bring a social
economic benefit to the region of approximately 40 million euros per annum
14
.
Figure 6: Monthly average NTC as part of total transfer capacity (2009-2016).
Source: energinet.dk as reported by the Danish Energy Regulatory Authority
15
4.2.3.
Deficiencies of the current legislation
The most relevant legislation is the Electricity Regulation, which contains a detailed
Annex on congestion management. However, it does not define bidding zones. In Section
1.7 it states that
"when defining appropriate network areas in and between which
congestion management is to apply, TSOs shall be guided by the principles of cost-
effectiveness and minimisation of negative impacts on the internal market in electricity."
More detail is provided under the CACM Guideline, which contains a detailed approach
to reviewing and defining prices zones (Articles 32 through 34), as detailed above.
Following TSOs' review and proposals Member States are required to "reach an
agreement on the proposal to maintain or amend the bidding zone configuration."
This approach lends itself to the maintenance of the
status quo
as there are likely to be
competing interests at stake. In particular, some Member States are unlikely to want to
amend bidding zones where it would create price differentials within their borders; it is
sometimes considered to be right for all consumers to pay the same price within a
Member State, and for all producers to receive the same price. The current legislation
does not, therefore, provide for the socially optimal solution to be agreed.
14
15
Investigation of welfare effects of increasing cross-border capacities on the DK1-DE interconnector.
Institute for Power Systems and Power Economics. RWTH Aachen University. June 2014. Study
commissioned by TenneT and Energinet.dk.
"STUDY
ON CAPACITY REDUCTIONS ON THE GERMAN
WESTERN DANISH BORDER (DE-
DK1) (Tender for Offers)"
-
http://f.industry-supply.dk/2bjt3mw1t748a8fa.pdf
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With regards to cross-zonal capacity, the current terms of the Electricity Regulation are
unclear and allow for different interpretations and application.
The Evaluation Report concludes that
"the Third Package clearly lacks rules for the
development and functioning of short markets as well as rules that would enable the
development of peak prices reflecting actual scarcity in terms of time
and location," and
that
"given the economic importance (and distributive effects) of the decisions TSOs have
to agree on, experience has shown that voluntary cooperation between TSOs was not
able to overcome the problems that block progress in the internal electricity market (e.g.
definition of fair bidding zones, effective cross-border curtailments)"
4.2.4.
Presentation of the options
Option 0: BAU and stronger enforcement
This option would entail relying on existing legislation to improve the configuration of
bidding zones. The likelihood of seeing any meaningful change as a result of this process
is minimal. Existing provisions under the Electricity Regulation are arguably not
sufficiently clear and robust to enforce a structure which reflects systematic constraints in
the interconnected system. The provisions of the CACM Guideline do not provide for a
clear decision-making process which provided any degree of certainty that the change
will be made, but rather it is left to individual Member States to make the decisions even
though these decisions have significant cross-border impacts.
Voluntary cooperation
As highlighted above, the evidence suggests that voluntary cooperation will not result in
progress in this area, as there has been to date already significant opportunity to effect the
necessary changes voluntarily.
Option 1: Move to a nodal-pricing system
A nodal pricing system would be the most granular way of determining location-based
energy prices. In theory, this would eliminate the need for remedial actions by the TSO to
alleviate congestion as the price of energy would determine exactly where it should be
dispatched from. It would also create more accurate investment signals in new generation
and infrastructure
in the case of the former in areas with higher prices, reflecting more
scarcity.
Moving to a nodal pricing system would require a fundamental change in the way
European energy markets are structured
current arrangements for cross-border trading
(market coupling) would need to be redeveloped, implying significant IT and procedural
changes. It would also be a significant change for market participants. The cost impact of
this would, in the short-term, likely out weight the benefits.
Option 2: Introduce locational signals through other means
It is possible to introduce signals for investment and/or dispatch through other means
than a market-based energy price. The main alternative method is through transmission
tariffs
i.e. charging generators less in areas where more capacity and energy is required,
and more where it is not. This can provide effective signals. It would mean a fundamental
change to the tariffs structure as around half (15) of Member States do not apply
transmission tariffs to generation. Further, this would not necessarily affect dispatch as, if
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charges are based on capacity, it becomes part of a generators fixed cost and will not
affect when they generate. Moving to 'energy-based' charges could add distortions into
the market as it would be very difficult to engineer this in a way which reflected the
congestion and the dynamic-nature of production. Indeed, ACER has recommended the
removal of energy based transmission charging on generators.
Option 3: Improve bidding zone review and decision-making process
As mentioned above, a review process is already detailed as part of the CACM
Guideline. There is a requirement to review both existing and possible alternative
configurations, the latter of which is triggered by specific circumstances. This option
would see a strengthening of the decision-making process as a result of the review, in
particular to ensure that the cross-border impacts of bidding zone configurations are
appropriately taken into account. This would be achieved explicitly clarifying existing
requirements for price zone borders to be based on congestion and not Member State
borders. Procedurally, more powers would be given to EU institutions to decide on price
zone configuration following the review. There could also be some amendments to the
review process itself to ensure that it can show the optimal solution.
The option would be coupled with strengthened legal provision that make clearer the
allowed derogations to the overriding rule that cross-zonal capacity must not be limited
to solve internal congestion, and make any derrogation subject to regualtory oversight.
4.2.5.
Comparison of the options
Maintaining the current system of review, and leaving the final decision-making in the
hands of national authorities, would be the simplest option and the one which would
yield the least disruption. However, as highlighted above, the process lends itself to
maintenance of the
status quo
as decisions will be made on an individual, rather than
collective basis. Difficulties have already arisen in the process (relating to some
ambiguities in the current legislation). The benefits of price zone boundaries, reflecting
structural congestions would not be seen, or would only partially be realised, if there is
no coordinated decision. These have been estimated to be between 300-400 million euros
per annum
16
to around 800 million euros
17
.
The second option (Option 1), to move to a nodal pricing system, would be the most
complex to implement. It would involve a complete redesign of the current system. It
would involve fundamentally moving away from the current market setup and would
significant changes to trading arrangements. By way of example, the current approach for
coupling national markets would likely need to change significantly, which would
involve large changes to IT and practices of traders, TSOs, power exchanges, suppliers
and generators. The costs of change would be significant. Burstedde, in an analysis of a
number of central European countries
18
found that there would be overall savings in the
16
17
18
Bauer, ibid.
Duthaler, C. (2012): "A
network and performance based zonal configuration algorithm for electricity
systems",
Dissertation, EPFL, Lausanne (Switzerland)
Comprising of AT, CH, DE, NL, VE and FR
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total cost of electricy supply from a nodal model, compared to a model based on bidding
zones around Member State borders, of around 940 million euros, mostly due to
redispatch costs. However, she also concluded that "the increase in overall system costs
which results from aggregating nodes into zones remains negligible in relative terms" and
that there would be savings from any move from nationally-based bidding zone
borders
19
.
The assessment of a nodal model will also form part of the review of bidding zones
structures by TSOs
it is therefore considered premature to conclude that Europe should
move to such a model before this review has concluded; the process will allow a proper
assessment of the different options and a decision can be taken on the basis of this.
Option 2 would require the introduction of administered locational signals. It is very
unclear what the costs and benefits of this approach would be, given that it would depend
on the prices set. If it were done on a capacity basis it would only impact the investment
signals, and not dispatch signals. If it were done on an energy basis, then it could add
significant distortions, e.g. by changing the merit order between different plants. This
would be counter-productive and erode the benefits from the market design initiative.
Option 3 builds on the system already established in the EU, as well as processes already
developed as part of the CACM Guideline. However, by moving to a more coordinated
decision-making process, one which does not prejudice the assessment of the benefits
and the costs of potential alternatives by TSOs, the likelihood that decisions are taken
which reflect the cross-border impacts of the bidding zone structure is greatly increased.
A more appropriately defined bidding zone structure could reduce the need for remedial
actions, such as redispatch, reduce unscheduled flows in the form of loop flows, and
improve signals for investment. Even so, an improved bidding zone structure would not
eliminate internal congestion. Strengthened provisions in the Electricity Regulation to
provide very clear rules on when cross-border capacity can be limited will help alleviate
the economic impacts of this happening in order to address internal issues.
The benefits of better locational signals are further articulated as part of the wider option
to address uncertainty on future investments (Problem Area II, which includes policies on
scarcity pricing and price caps, resource adequacy planning and capacity mechanisms) in
Section 6.2.2.
4.2.6.
Subsidiarity
Networks in the EU energy market are highly meshed and therefore energy trading in one
part has a significant part on another part. There are, however, naturally bottlenecks in
the system that prevent unhindered flow of energy
termed congestion. These do not
necessarily (and, in the case of the continental and Nordic synchronous areas) follow
Member State borders.
The Third Package already contains provisions relating to congestion management,
requiring procedures to be put in place, which is further elaborated by the CACM
19
Around 280 million euros in the case of moving to 9 zones.
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Guideline. It is important to have a harmonised approach to the management congestion
in order to manage it cost-effectively across the market and allow for maximum cross-
border trading.
Markets are split based on price zones, where the wholesale price is the same for each
given timeframe. These provide locational signals for dispatch and investment.
Whilst the Third Package has achieved much, further action is needed at the EU-level
price zones based on Member State borders do not reflect the actual locational need for
investment or demand for energy in a particular location. More coordinated action is
therefore necessary to direct dispatch of energy and investment in infrastructure based on
where it is needed and will provide most benefit to the EU interconnected system as a
whole. This will become increasingly important with more and more variable sources of
generation coming online over the coming years.
Action is already underway reviewing the structure of price zones in the EU. However,
the decision-making is still left at the national level, which lends itself to maintenance of
the
status quo,
which can have negative cross-border impacts (such as unscheduled flows
of energy from one country to another as a result of inefficient price signals).
4.2.7.
Stakeholders' opinions
A large number of respondents to the Energy Market Design consultation agreed that
energy prices should not only relate to time, but also locational differences in scarcity
(e.g. by meaningful price zones or locational transmission pricing). While some
stakeholders criticised the current price zone practice for not reflecting actual scarcity
and congestions within bidding zones, leading to missing investment signals for
generation, new grid connections and to limitations of cross-border flows, others recalled
the complexity of prices zone changes and argued that large price zones would increase
liquidity.
WindEurope (formally EWEA) commented that
"[w]holesale electricity prices reflecting
scarcity and physical constraints, including transmission capacity, are desirable in a
fully functional electricity market. This is already expressed in the present zonal pricing
model inside bidding zones and between bidding zones where price differentials signal
the need for transmission investments."
In their joint response to the consultation, ACER/CEER stated that
"[p]rices reflecting
scarcity (both in terms of time and location) of generation resources in each bidding
zone of organised markets in the different timeframes (day-ahead, intraday and
balancing) should become a key ingredient of the future market design."
EURELECTRIC
"generally favours larger bidding zones as they present more
advantages for the functioning of the market and its liquidity, however bidding zone
configuration should duly take into account the grid capacity. Zones should respect
structural bottlenecks that do not necessarily correspond to national borders."
The European Association for Storage of Energy (EASE) said that
"[p]rices
need to
reflect the physical limitations of the grid in order to deliver optimal locational signals
for investment, consumption and production."
Another is example is that of Norderegi, who view is that "[f]undamentally,
the borders
between Bidding Zones should be based on the physical characteristics of the power
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system. Bidding Zones should be aligned with where structural constraints occur.
Leading principle is that cross border trade must not be restricted. Moving internal
national transmission bottlenecks to national borders must not be used as a congestion
management method."
On the other hand, some stakeholders highlight risks to changes in price zone
configuration. For example, the European Energy Exchange (EEX) states that
"The
development towards large, cross-border bidding zones supports the efficiency of the
power system by integrating markets. Supply and demand can be brought together more
efficiently. The prerequisite for this is grid expansion. Delayed or insufficient grid
expansion even in a national context has a negative impact on the market as a whole, as
is currently seen in the discussion of splitting the German/Austrian bidding zone. Such a
decision would be a huge step back in the creation of the internal market, splitting
Europe’s most liquid bidding zone, decreasing the possibilities of risk mitigation and
eventually causing higher energy prices for consumers."With
regards to congestion
management, there have been significant concerns raised by industry about the practice
of limiting cross-border capacity to deal with internal congestion. For example,
Nordenergi have said, in a public letter to the European Commission, that the
"principle
that congestion needs to be managed where it occurs must be maintained as the
governing rule in an internal market, and this principle does not allow for congestion to
be moved to national borders in the extent and in the non-transparent manner that seems
to be the case on the mentioned Nordic borders"
and that
"besides the continuous welfare
losses due to curtailments of cross-border capacities, there are in addition severe long-
term negative effects through inefficient investment signals to both generators,
consumers and TSOs."
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4.3. Minimise investment and dispatch distortions due to transmission tariff
structures
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4.3.1.
Summary table
Objective: to minimise distortions on investment and dispatch patterns created by different transmission tariffs regimes.
Option 0: Business as usual
This option would see the
status quo
maintained, and transmission tariffs set
according to the requirements under Directive
72 and the ITC regulation.
Stronger enforcement and voluntary
cooperation:
There is no stronger enforcement action to be
taken that would alone address the objective.
Voluntary cooperation would, in part, be
undertaken as part of implementation of
Option 2.
Pros: Minimal change; likely to receive some
support for not taking any action in the short-
term.
Option 1: Restrict charges on producers
(G-charges)
This option could see the prohibition of
transmission charges being levied on
generators based on the amount of energy
they generate (energy-based G-charges)
Option 2: Set clearer principles for transmission
charges
This option would see a requirement on ACER to
develop more concrete principles on the setting of
transmission tariffs, along with an elaboration of
exiting provisions in the electricity regulation where
appropriate.
Option 3: Harmonisation
transmission tariffs
Full harmonisation of
transmission tariffs.
Description
Pros
Eliminating energy-based G-charges
would serve to limit distortionary effects
on dispatch of generation caused by
transmission tariffs. Social welfare
benefits of approximately EUR 8 million
per year. Would impact a minority of
Member States (6-8 depending on design).
Social welfare benefits relatively small
could be outweighed by transitional costs
in the early years. Can be considered
'incomplete' as a number of other design
elements of transmission tariffs contribute
to distortionary effects.
Unlikely to a proportionate
response to the issues at this
stage; given the technicalities
involved, it could be more
appropriate to introduce such
measures as implementing
legislation in the future.
Most suitable option(s): Option 2
aside from some high-level requirements, given the complexity of transmission charges, the precise modalities should be set-out as part of implementing
legislation in the future if and when appropriate. The value in Option 2 will be to set the path for the longer-term.
Cons
In the longer-term, likely to be a drive to do
more and maintaining the
status quo
unlikely
to be attractive; risks of continued divergence
in national approaches.
Provides an opportunity to move in the right direction
whilst not risking taking the wrong decisions or
introducing inefficiencies because of unknowns;
consistent with a phased-approach; could eliminate
any potential distortions without the need to mandate
particular solutions; consistent with the introduction
of legally binding provisions in the future, e.g.
through implementing legislation.
Still leaves the door open for variation in national
approaches; will not resolve all potential issues.
Minimises distortion between
Member States on both
investment and dispatch;
creates a level-playing field.
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4.3.2.
Description of the baseline
Tariffs are charged on demand and/or production in order to recover the costs associated
with building, maintaining and operating transmission and distribution infrastructure.
They can be used merely as a cost recovery tool, but also as a means to incentivise
investments and behaviours. They also have the potential to have distortionary effects. In
this annex, the focus is on the design of transmission tariffs, with distribution tariffs
discussed further in Annex 3.3. However, there are potentially important interactions,
which are touched on further below.
There are a number of decisions that regulatory authorities can take on the design of
tariffs. These are summarised below:
Figure 1
building blocks of transmission tariffs
Source: Cambridge Economic Policy Associates Ltd for ACER.
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The Third Package, and more specifically the Electricity Directive and Electricity
Regulation, contain specific provisions for the charging of transmission tariffs.
Requirements under the Directive include that tariffs, or the methodologies for
calculating them, must be fixed or approved by NRAs in accordance with transparent
criteria
20
and sufficiently in advance of their entry into force
21
.
Article 14 of the Electricity Regulation provides further requirements, which include:
-
that
"[c]harges applied by network operators for access to networks shall be
transparent, take into account the need for network security and reflect actual costs
incurred insofar as they correspond to those of an efficient and structurally
comparable network operator and are applied in a non-discriminatory manner;"
and
that,
"[w]here appropriate, the level of the tariffs applied to producers and/or
consumers shall provide locational signals at Community level, and take into account
the amount of network losses and congestion caused, and investment costs for
infrastructure."
-
More specific requirements are provided for under the inter-transmission system operator
compensation mechanism ("ITC") regulation
22
. This regulation sets down limits on the
average annual transmission charges that can be applied in each Member States to
electricity producers
23
. The regulation also required ACER to provide an opinion to the
Commission regarding the appropriateness of the range of charges, which it did on 15
th
April 2014.
In the opinion, ACER stated that it deemed it important that charges on generators ("G-
charges")
are "cost-reflective,
applied appropriately and efficiently and, to the extent
possible, in a harmonised way across Europe."
It recommended that: G-charges based on
energy produced (energy-based) should not be used to recover infrastructure costs;
energy-based G-charges should be set at 0 euros/MWh, except where they are used for
recovering the costs of system losses or costs relating to ancillary services. They
concluded, however, that it was unnecessary to propose restrictions on charges based on
connected capacity of the generation (what they term power-based charges) or fixed
(lump sum) charges.
However, prior to this opinion, a report by Frontier Economics for Energy Norway,
published in May 2013
24
, concluded that the potential for welfare loss is significant, with
effects on investment more significant than operational decisions, and strong welfare
losses result from a lack of harmonisation.
20
21
22
23
24 "
Art 37(1)(a)
Art 37(6)(a)
Commission Regulation (EU) No 838/210 of 23 September 2010 on laying down guidelines relating to
the inter-transmission system operator compensation mechanism and a common regulatory approach
to transmission charging,
OJ L 250 24.09.2010, p5-11
0-2 EUR /MWh in Romania; 0-2.5 EUREUR /MWh in UK and Ireland; 0-1.2 EUR/MWh in Denmark,
Sweden and Finland; and 0-0.5 EUR/MWh in all other Member States.
Transmission tariff harmonisation supports competition",
a report prepared for Energy Norway, May
2013
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Subsequently, and with the possibility existing to develop a 'network code
25
' to
harmonise transmission tariffs, ACER commissioned a scoping study from Cambridge
Economic Policy Associates Ltd (CEPA), which was finalised in August 2015. CEPA
concluded that, whilst there are theoretical distortions introduced by different charging
regimes in different Member States, the benefits of a short-term regulatory response (e.g.
harmonising through a network code) were unlikely to outweigh the potential costs of
change. However, they also concluded that in the longer-term, there is a stronger case for
further harmonisation "principally
based on the need for greater consistency and
application of "optimal" tariff structure that reflect the costs generating by market
participants' decisions."
Figure 2
Connection and generation tariffs in various countries
Source: Cambridge Economic Policy Associates Ltd for ACER, based on analysis of ENTSO-E data.
4.3.3.
Deficiencies of the current legislation
As detailed above, a framework for transmission tariffs is provided for in the Electricity
Directive, Electricity Regulation and in the ITC Regulation
26
. These all provide
significant scope for national differences without a view on how any potential negative or
distortionary impacts can be resolved. Further, the ACER recommendation has not been
implemented into the ITC Regulation.
25
26
A Commission Regulation developed under procedures laid down in the Electricity Regulation.
Commission Regulation (EU) No 838/2010 of 23 September 2010 on laying down guidelines relating
to the inter-transmission system operator compensation mechanism and a common regulatory
approach to transmission charging,
OJ L 250, 24.9.2010, p. 5–11
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The Evaluation Report points out that
"whilst the Third Package contains provision on
transmission tariffs, their level and design still differ significantly between Member
States. This has the potential to distort price signals."
4.3.4.
Presentation of the options
Option 0
BAU
This option would involve maintaining the
status quo,
and the provisions relating to
tariffs in the Third Package and associated legislation would remain the same.
Option 0+: stronger enforcement and voluntary cooperation
There is no additional enforcement action to take that would address the points above.
Option 2 would entail a level of voluntary cooperation as part of its implementation
i.e.
that regulatory authorities voluntarily work towards implementation of key principles
developed by ACER in advance of further legally binding obligations.
Option 1 - Restrict charges on producers (G-charges)
This option would involve eliminating energy-based transmission charges that can be
charged on producers (except where they are used for recovering the costs of system
losses or costs relating to ancillary services), as set out in the ACER opinion. It would
have an effect in the following Member States, who apply such charges
27
.
-
Denmark
-
Finland
-
France
-
Portugal
-
Romania
-
Spain
In implementing this option, those Member States would have a choice as to how they
then treat generators. They could either remove charges on generators all together,
meaning that all tariffs would be charged to consumers, or they could replace them with
alternative tariffs, namely ones based on the capacity or a lump-sum tariff. For the
purposes of this analysis, it is assumed that these Member States continue to levy charges
on generators.
Option 2 - Introduce more extensive and concrete principles on the setting of
transmission charges
This option would involve giving responsibility to ACER to develop guidance addressed
to national regulatory authorities, which would be developed over a time frame of 1-2
years. It would provide a basis on which NRAs could make their decisions with a view to
27
Excluding Austria and Belgium, who apply energy-based charges for ancillary services and/or losses
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more concrete legal measures in the future, notably though implementing legislation such
as a network code or guideline. Such principles could relate to: the definition and
implementation of cost-reflectivity; charges applied to consumers versus charges applied
to producers; the types of costs which are to be included; locational and/or time-of-use
element of charges; and principles relating to transparency and predictability. It would be
accompanied by some higher-level principles in legislation, for example requiring
regulatory authorities to minimise any distortions between transmission and distribution
tariffs - e.g. on their impact on generators.
Option 3 - Full harmonisation
This option would not only see the process and criteria harmonised but also the
components and levels of transmission charges so that the charges on load and
production and comparable in each Member States. This would include the elaboration of
a harmonised definition of cost-reflectivity, so that all Member States charge producers
and/or consumers on the same basis. Further, it would ensure that costs related to
ancillary services and losses are treated in the same way.
This option could be accompanied by a requirement that transmission charges include a
locational element reflecting, in particular, transmission constraints within a price zone.
4.3.5.
Comparison of the options
G-Charges
The option to remove energy-based transmission tariffs on generators has been assessed
quantitatively based on ECN's COMPETES model
28
. COMPETES is a power
optimisation and economic dispatch model that seeks to minimise the total power system
costs of European power market whilst accounting for the technical constraints of the
generation units, transmission constraints between the countries as well as transmission
capacity expansion and generation capacity expansion for conventional technologies for
given generation intermittency (e.g., wind, solar) and RES E penetration in EU Member
States. The model also decommissions the existing conventional power plants that cannot
cover their fixed costs.
In order to provide a frame of reference, three scenarios were assessed as regards the
change on total system costs
29
, TSO surplus
30
, payments by consumers
31
and producer
surplus
32
for a reference year of 2030:
-
Reference case where no tariffs are charged. Implicitly, therefore, all the
transmission costs are covered by congestion income and electricity prices
" Transmission Tariffs and Congestion Income Po6licies",
ECN, DCision, Trinomics (Intermediate
Report)
29
Generation OPEX + Generation CAPEX + Fixed O&M + Transmission Investment
30
G-charge payments + Congestion income - Transmission CAPEX
31
Payments consumers make for their electricity use, i.e. electricity use (in MWh) x electricity price (in
Euro/MWh)
32
Short run profits - Gen CAPEX - G-charge payments
28
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-
-
charged to consumers - this was created for the purposes of assessing the options
below, as opposed to being an option itself.
Option 0: Reflecting the current situation with different G-tariffs per country
(Euro/MWh or Euro/MW differing per country). The tariffs are taken from the
ACER internal G-charges monitoring report.
Option 1: Implementing capacity-based tariffs only in which case energy-based
Euro/MWh tariffs of Option 0 are converted to Euro/MW capacity-based tariffs.
A figure for the total social welfare was calculated as {Change in TSO surplus + Change
in Producer surplus - Change in Consumer payments}. The results for the total and
comparison of the options are provided in table 1 and 2 respectively.
Table 1
total values, all countries (million EUR)
System
Costs
Reference (no tariffs)
Option 0 (current
situation)
Option 1 (cap.-based
tariffs)
85,082.2
85,094.7
85,094.0
TSO
surplus
2,102.3
3,044.6
2,875.1
Consumer
payments
226,821.0
227,617.6
227,298.2
Producer
surplus
138,455.7
138,282.9
138,141.1
Table 2
option comparison, all countries (million EUR)
System
Costs
Option 0 vs
Reference
Option 1 vs
Reference
Option 1 vs
Option 0
12.5
11.8
-0.8
TSO
surplus
942.3
772.8
-169.5
Consumer
payments
796.6
477.2
-319.4
Producer
surplus
-172.8
-314.6
-141.8
Social
welfare
-27.1
-19.0
8.1
Moving from the current system (Option 0) would result in an increase in economic
efficiency of generation dispatch and investment decisions as well as overall competition
between generators. More specifically, there would be some limited effect on dispatch
and investment decisions of generators in countries that have to replace energy-based by
capacity-based or lump sum G-charges. On the other hand, decisions of generators in
countries that currently either have no energy-based G-charges or only non-energy based
G-charges in place would not be affected. Cross-border competition between generators
is likely to induce regulatory competition between Member States and, as such, likely to
serve as an implicit upper limit to all types of G-charges, preventing larger divergence of
within the EU. However, this this does not imply that G-charges will be set to their
optimal long-run cost-reflective level i.e. the level that stimulates generators and
consumers to take investment and siting decisions that minimise overall system costs,
which is the sum of generation, network, and societal costs. Rather it is likely that the G-
charges of the largest Member States in Continental Europe become the benchmark. In
the absence of incentives for multilateral coordination of country practices regarding
transmission charges for generators (either regional or EU-wide), this option can
therefore be considered as incomplete. As can be seen from the above, the social benefits
of moving from the current system would be in the region of EUR 8 million a year
a
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small proportion of overall system costs. This risks being outweighed by implementation
costs.
Principles for transmission charges
It is naturally more difficult to quantitatively assess the impacts of this option, as they
will by-and-large depend on the precise design of such principles and the extent to which
they are implemented prior to any legal mandate (e.g. from implementing legislation
such as a network code). Therefore this option is assessed qualitatively.
A harmonisation of the tariff principles to better reflect the grid costs will have a positive
impact on the efficiency of dispatch and investment decisions by generators. Concerning
the latter, harmonised tariff principles will improve the investment climate for power
generation by offering a higher predictability with regard to the expected tariff
development. It will overall reduce competition distortions amongst generators, but the
impact of tariff harmonisation on the competitiveness of individual generators can be
positive or negative depending on the current situation.
As discussed above, there are a number of issues that need to be addressed in the design
of tariff structures. These include the extent to which charges are applied to generators as
compared to consumers (the Generation: Load or "G:L" split), the basis on which they
are charged, the interpretation of the principle of 'cost reflectivity,' whether there are
signals on location or time of use, etc. Whilst the discussion here has mostly been
focused on generators and the wholesale market, a significant proportion of transmission
tariffs on are charged on consumers/load
all Member States apply charges to load, with
some applying all of them (15). Therefore the design of tariff structures can have a
significant impact on consumers, both financially and economically, and on their
behaviour. There are clearly a number of complexities which will need discussion among
regulators, TSOs and stakeholders to determine the most beneficial approach.
Despite the fact that national tariff differences are only one of the drivers of current
distortions of dispatch and investment decisions between Member States, the focus on
cost reflectivity of transmission signals is key in an increasingly interconnected system in
order to prevent negative spill-over effects.
Harmonisation
Full harmonisation would involve decisions on many of the same topics as mentioned
above, but determining them in legislation immediately. It would require upfront
decisions on the 'optimal' tariff structure, something that so far has not been determined
with a clear articulation of the benefits. As mentioned above, there already exists a legal
mechanism for harmonising tariffs
Article 8 of the Electricity Regulation already
provides the ability to create implementing legislation, in the form of a network code,
something that would be developed collaboratively by TSOs, regulators, ACER and
stakeholders. Doing this as part of Market Design is very unlikely to elicit better results
than could be achieved with the detailed and ongoing participation of experts that the
development of a network code would involve. Further, flexibility would be
compromised. Given the complexity and the amount of 'unknowns' there is a significant
risk that any attempt to fully harmonise would result in issues that could only be
identified once Member States start to implement the requirements; a network code
allows for significantly more flexibility to respond to such issues if and when they arise.
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Requirements set out in an ordinary legislative act would prove much more difficult to
adapt.
There are two sub-issues that have also been considered as part of this option: that of
harmonised charges relating to ancillary services and grid losses; and locational-
charging.
There is significant diversity in charging methodologies with regards to ancillary
services. For instance, in most Member States, all costs for balancing services are
recovered via charges on load. Only in a few Member States do generators pay grid
charges that comprise a specific contribution for the cost related to balancing services
33
.
With regards to grid losses, again most European countries recover them through charges
on load, but in a few countries the related cost is partly or fully charged to generators
34
.
If charges for ancillary services were to be harmonised, the impact on short-term and
long-term electricity system efficiency would depend on the level of the charges and the
charging modalities but may not be substantial. If charges for ancillary services were to
be more correctly and transparently allocated to the market parties (generation and load)
on basis of needs of the parties, market operators would contribute to minimising the
overall need for such services, particularly frequency-related services, with more flexible
demand and supply. It could, however, contribute to a higher cost-reflectiveness and
fairer cross-border competition amongst generators as the currently diverging charging
practices and cost allocation can lead to competition distortions between power
generators active in the same integrated regional market.
The impact of a harmonised charging method of grid losses via a specific tariff on the
short-term and long-term electricity system efficiency would be very limited. Only if grid
losses are calculated and charged individually to grid users would there be a higher
impact on the short and long-term system efficiency. There is, however, scope to correct
competitive distortions on generators, although this will only have an impact in those few
Member States where losses are (partly) charged to generators; in the large majority of
Member States grid losses are entirely charged to load.
33
34
Austria (2.81 EUR/MWh in 2015), Belgium (0.9111 EUR/MWh, which represents 50 % of the overall
reservation cost for balancing services), Bulgaria (3.65 EUR/MWh to be paid only by wind and solar
generators to cover the cost for balancing services), Finland (0.17 EUR/MWh), Ireland (0.3
EUR/MWh), Northern-Ireland (0.31 EUR/MWh), Norway (0.21 EUR/MWh
the costs for procuring
balancing services are in Norway divided equally between generation and load) and Sweden (0.087
EUR/MWh). In Great Britain, the costs incurred by the TSO (NGET) in balancing the transmission
system are recovered through Balancing Services Use of System (BSUoS) Charges, which are shared
equally between generators and suppliers.
ACER, Internal Monitoring Report on Transmission charges
paid by the electricity producers,
May 2016.
Austria (0.45 EUR/MWh in 2015), Belgium (balancing responsible parties are obliged to inject,
depending on the time, 1.25 or 1.35 % more than their offtake from the grid), Greece (average = 1.08
EUR/MWh based on zonal Generation Losses Factors), Ireland and Northern-Ireland (1.36
EUR/MWh), Norway (average = 0.57 EUR/MWh based on marginal loss rates which are different
depending on the location and the time), Romania (0.23 EUR/MWh) and Sweden (0.40 EUR/MWh) -
ACER,
Internal Monitoring Report on Transmission charges paid by the electricity producers,
(May
2016).
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With regard to providing appropriate locational signals for investment and dispatch of
generation through tariffs, clearly this can only be achieved where generators are charged
tariffs (so in 12 Member States) and, with regards to the latter, only where there is
energy-based charging (8 Member States). Administratively setting tariffs to affect
dispatch could add significant distortions into the energy market and requiring this is not
an option that is explored further. As to investment signals, i.e. making it more expensive
to locate in areas of less need, and less expensive in areas of higher need, proponents
would argue that it gives economic signals about where to site new generation capacity
and use existing capacity, and that it reflects the costs to the transmission network that
generators cause. However, opponents believe that locational charging is designed to
reflect a generating mix predicated on generation close to centres of demand and not
designed to encourage a fundamental shift to more mixed and geographically spread
energy supply. Any concrete impact of location-based charging on economic efficiency
will largely depend on the level of the fee and its form, and it is not clear that this would
override other factors influencing siting (regulatory, planning, meteorological, etc.).
Further, it is potentially complex to implement and could add uncertainty to generators. If
price zones are formed based on structural congestion, part of an objective of Market
Design (see Annex 4.2) this could anyway remove the need to introduce locational
signals by other means
i.e. as the energy price would provide such signals. This is not
to say that the approach is not succeeding in those countries that already employ it (e.g.
GB, Sweden) or that it is definitely unsuitable for the future, but rather that the first step
should be to implement appropriate defined price zones and that further, detailed
consideration is needed at the regulatory level on whether and how to implement such an
approach. It is, therefore, not considered an appropriate response to design or mandate its
introduction as part of this legislative package.
Summary
Given the number of design features and complexities regarding transmission tariffs, and
the potentially small benefits associated with harmonising the less-complex aspects
individually, it is concluded that the most appropriate option is to leave any full
harmonisation to future implementing legislation as part of a network code or, if
appropriate, through an amendment to existing implementing legislation
35
. This will
minimise disruption and implementation costs, allow the precise package to be worked
up over time and with full involvement of experts, and also allow for the interactions
between distribution tariffs and transmission tariffs, and their impacts on consumers and
generators at both connection-levels, to be more fully reflected. Further, it will allow
time to determine the most beneficial approach and tackle the most significant issues
holistically. The development of principles to guide NRAs when designing tariffs
regimes (Option 2) would provide the first step in this process, and facilitate early
decisions and implementation prior to any legally binding instrument. As the topic falls
within the regulators' field of competence, this would be appropriately led by ACER.
Further, augmentation of the high-level principles in the Electricity Regulation is
necessary to reflect evolution of the market since they were originally introduced, for
35
E.g. changes to G-charges could be effected by amending the ITC regulation.
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example to avoid any discrimination between distribution-connected and transmission-
connected generation when setting or approving tariffs.
4.3.6.
Subsidiarity
Charges applied to generators in relation to their connection to, and use of, networks can
be significant. Differences in these charges can therefore have an effect on decision-
making, whether it is on investment locations or on dispatch of energy, and can therefore
add distortions into the market. Given the highly integrated nature of EU electricity
markets, this can add distortions between Member States.
EU-level action is therefore warranted, in order to ensure the minimum degree of
harmonisation needed to avoid distortion in investment and generation is achieved. The
Third Package already lays down a number of rules relating to these changes (notably
Article 14 of the Electricity Regulation), and also requires NRAs to take an active role
(under the Electricity Directive). Further provisions relating to transmission tariffs are
contained in the inter-transmission system operator completion mechanism (ITC)
Regulation, aimed at the issues mentioned above.
Whilst much has been achieved, there is still scope for improvement, particularly given
the importance of minimising distortions to the benefit of consumers. EU-action is
needed to addresses this as it needs to be coordinated across the EU.
4.3.7.
Stakeholders' opinions
Stakeholder feedback suggests there is a case for change, particularly in the medium to
long-term. In 2015, ACER ran an exercise looking at potential harmonisation of tariffs
through the development of a network codes. This included stakeholder questionnaires
(run by Cambridge Economic Policy Associated
CEPA). In their report, CEPA
highlighted a number of points:
-
The majority of stakeholders (79 responses) across European countries consider
that the current electricity transmission tariff structures do impact on the efficient
functioning of the European electricity market;
Around 80% of respondents agreed that generators’ operational and investment
decisions are affected by transmission tariff structures;
The majority of respondents also considered differences in current transmission
tariff structures across Europe to be a source, or a potential source, of regulatory
and market
failure
in the IEM. Differences in transmission tariff structures across
European countries were identified by stakeholders as a problem today and
potentially in the future, citing distortions to operational (as well as investment
decisions) as a source of regulatory or market failure;
Over 60% of respondents also agreed or strongly agreed that differences in
transmission tariff structures across European countries could hamper cross-
border electricity trade and/or electricity market integration. Energy-based tariffs
were cited as a particular issue;
Around 70% of respondents believed that there are benefits that can be achieved
through harmonisation of transmission tariff structures. Only 7% of all
respondents rejected the idea that harmonisation of transmission tariffs would be
beneficial for the IEM;
-
-
-
-
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Further, Eurelectric, in their market design publication
36
, state that "[r]egarding
transmission tariffs applied to generators, their structure and methodologies to compute
the costs need to be harmonised. Furthermore, their levels should be set as low as
possible, in particular the power based charges (€/MW) which act as a fixed cost for
generation and therefore distort investment decisions."
36
"Electricity market design: Fit for the low carbon transition,"
Eurelectric (2016)
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4.4. Congestion income spending to increase cross-border capacity
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4.4.1.
Summary table
Objective: The objective of any change should be to increase the amount of money spent on investments that maintain or increase available interconnection capacity
Option 0: Business as usual
This option would see the current situation
maintained, i.e. that congestion income can be
used for (a) guaranteeing the actual availability of
allocated capacity or (b) maintaining or increasing
interconnection capacities through network
investments; and, where they cannot be efficiently
used for these purposes, taken into account in the
calculation of tariffs.
Description
Stronger enforcement: current rules do not allow
for stronger enforcement.
Voluntary cooperation: would offer no certainty
that the allocation of income would change.
Minimal disruption to the market; consumers can
benefit from tariff reductions
unclear whether
benefits of better channelling income towards
interconnection would provide more benefits to
consumers, given that it may offset (at least in
part) money spent on interconnection from other
sources.
Option 1
Further prescription on the use of
congestion income, subjecting its use
on anything other than (a)
guaranteeing the actual availability of
allocated capacity or (b) maintaining
or increasing interconnection
capacities (i.e. allowing it to be offset
against tariffs) to harmonised rules.
Option 2
Require that any income not used for (a)
guaranteeing availability or (b) maintaining or
increasing interconnection capacities flows
into the Energy part of CEF-E or its
successor, to be spent on relieving the biggest
bottlenecks in the European electricity system,
as evidenced by mature PCIs.
Option 3
Transfer the responsibility of using the
revenues resulting from congestion and
not spent on either (a) guaranteeing
availability or (b) maintaining
capacities to the European Commission.
De facto all revenues are allocated to
CEF-E or successor funds to manage
investments which increase
interconnection capacity.
Pros
More guarantee that income will be
spent on projects that increase or
maintain interconnection capacity and
relieve the most significant
bottlenecks; could provide around 35%
extra spend; approach reflects the EU-
wider benefits of electricity exchange
through interconnectors; can be linked
to the PCI process.
Guarantees that income will be spent on
projects that increase or maintain
interconnection capacity and relieve the most
important bottlenecks; could provide up to
35% extra spend; approach reflects the EU-
wider benefits of electricity exchange through
interconnectors; firm link with the PCI
process.
Best guarantee that income will be
spent on the biggest bottlenecks in the
European electricity system, ensuring
the best deal for European consumers in
the longer run; approach reflects the
EU-wider benefits of electricity
exchange through interconnectors; to be
linked to the PCI process.
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Missing a potentially significant source of income
which could be spent on interconnection and
removing the biggest bottlenecks in the EU.
Restricts regulators in their tariff
approval process and of TSOs on
congestion income spending.
Additional reporting arrangements will
be necessary.
Requires stronger role of ACER.
Restricts regulators in their tariff approval
process and of TSOs on congestion income
spending.
Could mean that congestion income
accumulated from one border is spent on a
different border or different Member States.
Additional reporting arrangements will be
necessary.
Requires stronger role of ACER.
Could prove complicated to set up such
an arrangement; could mean that
congestion income accumulated from
one border is spent on a different border
or different Member States.
Requires a decision to apportion
generated income to where needs are
highest in European system. Will face
national resistance.
Will require additional reporting
arrangements to be put in place.
Requires stronger role of ACER.
Most suitable option(s): Option 2
provides additional funding towards project which benefit the EU internal market as a whole, while still allowing for national decision making in the first
instance. Considered the most proportionate response.
Cons
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4.4.2.
Description of the baseline
Congestion
37
income arises across an interconnection due to price differences on each
side of it. Such effects happen between price areas (i.e. bidding zones), as opposed to
between Member States. The higher the price difference, the greater the income
generated. Conversely, the greater the levels of interconnection, the more arbitrage
opportunities and, therefore, the lower the price differences each side. Congestion
income per MW is therefore lower.
The issue of optimising interconnection capacity from a private versus social cost-benefit
perspective has been analysed, among others, by De Jong and Hakvoort (2006; see also
De Jong, 2009).
38
They show that, under certain assumptions (two-node network with
perfect competition and linear supply and demand curves), the capacity that maximises
social benefits is twice the capacity that maximises private benefits. This relationship
changes a bit, however, when investment costs are also taken into account. In that case,
De Jong and Hakvoort show that the interconnection capacity that maximises social
value exceeds the capacity that maximises private profits by even more than a factor of
two.
37
38
The term ‘congestion’ means a situation in which an interconnection linking national transmission
networks cannot accommodate all physical flows resulting from international trade requested by
market participants, because of a lack of capacity of the interconnectors and/or the national
transmission systems concerned.
De Jong, H., and R. Hakvoort (2006),
Interconnection Investment in Europe
Optimizing capacity
from a private or a public perspective ?,
in : Proceedings of Energex 2006, the 11th international
energy conference and exhibition, 12-15 June 2006, Stavanger, Norway, pp. 1-8. De Jong, H. (2009),
Towards a single European electricity market
A structural approach to regulatory mode decision-
making,
Ph.D.-thesis, Technical University Delft, the Netherlands.
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Figure 1 - Optimum interconnection capacity from a social versus private benefit
perspective
Source: De Jong (2009), p. 261 (see also De Jong & Hakvoort, 2006))
Congestion income from interconnection capacity is a major source of revenues for
TSOs' investment in network expansion. Therefore, in theory, TSOs will invest in new
interconnection capacity as long as the congestion income outweighs the investment and
operational costs (including a reasonable rate of return) and the potential decrease of
congestion income on existing cross zonal interconnectors in the case that the new
interconnector serves as a substitute to existing interconnectors. From a social point of
view, this may result in underinvestment in interconnection capacity and, hence, in a sub-
optimal level of cross-border transmission capacity.
Partly to address this, Article 16 of the Electricity Regulation seeks to restrict how
congestion income can be used
39
. Specifically, it only allows it to be used to:
1. guarantee the availability of allocated interconnection capacity;
2. maintaining or increasing interconnection capacities through network
investments, in particular in new interconnectors;
3. to be offset against network tariffs; or
4. held on account until it can be spent on one of the above.
39
In the case of new interconnectors, exemptions can be given to these requirements subject to a number
of conditions being fulfilled.
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According to data from ENTSO-E, the total amount of TSO net revenues from
congestion management on interconnections was EUR 2.3 billion in 2014 and EUR 2.6
billion in 2015. Figure 2 presents the spending of congestion revenues in 2014-15
aggregated for all members of ENTSO-E, both in million EUR and as a % of total annual
revenues. These revenues amounted to, on average, EUR 2.275 million per annum in
2014-2015. Figure 2 shows that out of this amount, on average, EUR 374 million was
spent on capacity guarantees (16%), EUR 817 million on capacity investments (36%),
EUR 804 million on reducing transmission tariffs (35%) and EUR 280 million saved on
an account (12%). This implies that, on average, about half of the congestion revenues in
2014-15 were used to guarantee, maintain or increase interconnection capacity and,
hence, that
in principle
there is room for increasing this share by alternative Options.
It should be noted, however, that changing the rules on spending of congestion income
may not by itself be sufficient to stimulate investment in relieving the biggest bottlenecks
in the EU. There are a number of reasons why investment in interconnection capacity
might not be forthcoming: they are complex projects with a number of socio-economic
impacts, and often face barriers relating to, for example, planning; the decisions are
complex, and often require the involvement of two or more parties; additional
investments may be needed in national networks in order to accommodate new capacity.
Further, TSOs are able to cover the investment and operational costs of interconnectors
which are approved by their NRAs
not only from congestion revenues but also, or even
exclusively, from regulated transmission tariffs. Therefore, there is theoretically already a
source of funding for such projects, although in practice the regulated tariff system may
be considered too restrictive for socially optimal investments in interconnection capacity,
for instance because certain costs may not be approved to be part of the regulated cost
base, or because the allowed rate of return may be considered too low to cover the risks,
uncertainties or other challenges involved.
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Figure 2- Spending of congestion revenues in 2014-15 (in million EUR and as % of
total annual revenues for all countries)
Source: ENTSO-E (2014-15)
4.4.3.
Deficiencies of the current legislation
Current legislation is not providing for sufficient investments in bottlenecks within the
European electricity system. Whilst, as highlighted above, this is unlikely to be due, at
least solely, to how congestion income is spent, there is clearly scope for significantly
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more funding to be directed toward this ends from congestion income. As demonstrated
from the above figures, the amount spent on increasing or maintaining interconnection
capacity is less than half of the available funds. Further, despite existing bottlenecks and
interconnection levels well below the optimum ones, the legislation offers incentives to
NRAs to retain congestions, as the income they generate can be used to lower national
tariffs. There are also significant deficiencies in transparency with regards to the
spending of congestion income. Whilst current legislation contains obligations relating to
transparency, this is ineffective in practice and it proves difficult to assess how the
provisions of Article 16 are being applied. For example, it is unclear:
-
-
how the TSOs decide on the use of congestion revenues for either guaranteeing,
maintaining or increasing interconnection capacity;
whether and how the NRAs check (i) that TSOs have used congestion revenues
efficiently for either guaranteeing, maintaining or increasing interconnection
capacity, and (ii) that the rest of the revenues cannot be efficiently used for these
purposes;
on which criteria the NRA decides on the maximum amount used as income to be
taken into account when approving or fixing network tariffs;
how the congestion revenues are used during the period they are put on a separate
account;
the projects towards which the funds are being allocated, including the split
between investments towards capacity maintenance and capacity increases.
-
-
-
The Evaluation Report points out that "another
problem is the lack of adequate and
efficient investment in electricity infrastructure to support the development of cross-
border trade. ACER's recent monitoring report and other reports on the EU regulatory
framework stress that the incentives to build new interconnections are still not optimal.
In the current regulatory framework, TSOs earn money from so-called congestion rents.
If TSOs reduce congestion between two countries, their revenues will therefore decrease.
The Third Package has identified this dilemma and addressed through obliging TSOs to
use congestion rents either for investments in new interconnection or to lower network
tariffs. Experience with this rule has, however, shown that most TSOs prefer to use
congestion rents to lower their tariff to investing into new interconnectors."
4.4.4.
Presentation of new measures/options
Option 0
Do nothing.
This would maintain the
status quo,
i.e. rules on spending covered by Article 16 of the
Electricity Regulation. The methodology currently being developed under the Capacity
Allocation and Congestion Management regulation (CACM) would provide the main
rules on how the income is allocated between TSOs on each border.
Option 0+: Non-regulatory approach
Stronger enforcement of existing rules will not allow an improvement of the current
situation.
Voluntary cooperation will provide no certainty that there will be a change in the current
allocation of congestion income. Given there are already rules in place, a change to these
rules is needed to address the issue.
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Option 1
Harmonised use of congestion income
The first option would maintain all the options for the use of congestion income as
already provided for in the regulation, but be more prescriptive about when it can be
taken into account in the calculation/reduction of network tariffs. More specifically, it
would require that its use on anything other than (a) guaranteeing the actual availability
of allocated capacity or (b) maintaining or increasing interconnection capacities be
subject to harmonised rules developed by ACER.
These rules would clearly define the situation when, and when not, the alternative options
could be pursued. Indicatively, the possibility to decrease the network tariff through
congestion income would be allowed only when there is clear and justified evidence,
according to the ACER rules, that there are no cost-effective projects that would be more
beneficial for social welfare than tariff reduction. Rules would also detail how
long/which revenues could be kept in internal accounts until they can be effectively spent
for the above purposes.
This option would be combined with more transparency and additional rules for
publication and monitoring of this spending.
Option 2
Harmonised use of congestion income with basic CEF option
The second option would, similarly, restrict spending to (a) guaranteeing availability or
(b) maintaining or increasing interconnection capacities. If the income cannot be
effectively used on (a) or (b), it would flow into the Connecting Europe Facility for
Energy (CEF-E) or its successor, and be spent on relieving the biggest bottlenecks in the
European electricity system, as evidenced by mature PCIs. Unlike Option 1, there would
be no option to use the income when calculating tariffs until such time that all the biggest
bottlenecks have been removed (which practically will not happen in the foreseeable
future).
This option would, similarly to Option 1, include harmonised compliance rules to be set
out and monitored by ACER, and combined with more transparency.
Under this option, it is possible that congestion revenues that would normally be used to
lower the national network tariff accrued in one Member State will be spent in another
Member State allowing spending on those projects that would bring the greatest benefits
to the EU as a whole.
Option 3
Harmonised use of congestion income with full CEF option
The third option is an extension of the second. TSOs would, at the national level, be
permitted to use income for (a) guaranteeing the actual availability of allocated capacity
or (b) maintaining interconnection capacities. However, they would not be permitted to
use it to
increase
interconnection capacity, and neither could it be used against tariffs.
Instead, all income not spent on (a) and (b) above would be directed to the European
Commission,
de facto
to the CEF-E or successor funds, to manage interconnection
capacity. This way, the revenues that, up to now can be used by TSOs/NRAs for
increasing capacity or lowering network tariffs, would be spent on the biggest
bottlenecks in the European electricity system as evidenced by mature PCIs. Again, as
with Option 2, if and when all these are removed, income could then be taken into
account when calculating tariffs.
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This option would, similarly to Option 1, include harmonised compliance rules to be set
out and monitored by ACER, and combined with more transparency.
Again, under this option it is possible that congestion revenues accrued in one Member
State will be spent in another Member State allowing spending on those projects that
would bring the greatest benefits to the EU as a whole.
4.4.5.
Comparison of the options
The options have been compared against the following criteria:
-
Effectivity. Effectivity implies that, as much as possible, congestion income is
used to maximise the amount of cross-border capacity available to market
participants. The criterion assesses whether and to what extent the Options
achieve this objective;
Efficiency. Efficient use of congestion income means that the procedure for the
spending of congestion income provides a simple and straightforward approach to
guaranteeing that congestion income is used for maintaining or increasing the
interconnection capacity;
Transparency. The spending of congestion income should be transparent and
auditable;
Robustness. The spending rules should be set in such a way to avoid influence
over the rules beyond what it envisaged;
Predictability. The spending rules should allow a forecast of the financial
outcome and allow for reasonable financial planning by the TSOs involved;
Proportionality. Congestion income policy options should be commensurate with
the problem i.e. not going beyond what is necessary to achieve the objectives,
limited to those aspects that Member States cannot achieve satisfactorily on their
own, and minimise costs for all actors involved in relation to the objective to be
achieved;
Smoothness of transition. The current congestion income spending should not be
changed in a radical way in the short-term in order to limit the financial impact on
all system participants.
-
-
-
-
-
-
Effectivity
With respect to the effectivity of the policy options, all three positively contribute in
more or less the same manner. Currently, congestion income may be taken into account
by the regulatory authorities when approving the methodology for calculating network
tariffs and/or fixing network tariffs. In all three options this type of usage will be strongly
restricted or forbidden causing a larger share of the congestion income to be allocated to
maintaining and/or increasing cross-border capacity. However, for the actual construction
of these links, there may be additional barriers like the licensing procedures for the new
corridors, so the availability of more financial resources may not in all cases guarantee
interconnection expansion.
Efficiency
Currently, TSOs and NRAs have the possibility to allocate the congestion revenues in the
most economically efficient manner. However, due to flexibility at the national-level it
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cannot be guaranteed that congestion income will always be spent on maintaining and/or
increasing the available interconnection capacity. In each of the three options the level of
freedom for TSOs and NRAs to decide otherwise will be significantly reduced.
Since in Option 2 congestion income for investments are managed at a European level,
whereas the operational measures to guarantee or maintain the interconnection capacity
are dealt with nationally, this Option might be less effective than the other two.
Furthermore, there is some possibility that Member States prefer to withhold funds from
being transferred to a European institution by previous spending on operational
measures.
Transparency
There are currently reporting obligations for the TSO on the spending of congestion
income. It is nonetheless not entirely clear, which criteria are applied for allocating
congestion income to operational measures, investments in capacity expansion or
inclusion in the transmission tariffs. It is expected that each of the three options will
increase the transparency of the allocation and spending of congestion income.
Robustness
The present methodology for spending congestion income is monitored by the NRAs
whereas the revenues themselves are ring fenced. There is not much room to spend the
income for other purposes than that envisaged. Each of the three Options further narrows
down the discretion of TSOs and NRAs. In each Option a larger share of congestion
income will be used for investments, since decision making is either more heavily
regulated or transferred to the European level.
Predictability
Currently, it is not clear how congestion income will be spent. It does not only depend on
the operational costs needed to guarantee the cross-border capacity, but also to the
discretion of the TSOs (and the approval of the NRAs) in deciding how to spend the
income. Each of the three Options contributes to a better predictability. However, the
first option leaves more freedom to Member States to decide on new investments than the
other two options, under which the income is added to the CEF-E funds, which are only
used for PCI investment projects. In the latter case the predictability of the manner of
spending is very good.
With respect to spending congestion income on operational matters, clearer rules will
contribute to higher transparency on the amount of funds needed for it. This will
materialise in all three options.
Proportionality
If the objective of the policy options is to enhance the actual availability of the
interconnection capacity by relieving the financial constraint, each option that effectively
increases the financing of investments can be considered as proportional. With respect to
the implementation differences between the three options, it is debatable which measure
is more (or less) proportional than the other: adding detailing regulation (as in Option 1)
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or shifting decision making power from the national to the European level (as in Options
2 and 3).
Smoothness of transition
The smoothness of transition is assessed with respect to the amount of change involved
when implementing each Option with reference to the current situation. The
implementation of additional regulation does not significantly change the present powers
of TSOs and NRAs, which is why Option 1 is positive with respect to smoothness of
transition.
For Options 2 and 3 decision making on new investments and operational measures for
maintaining the interconnection capacity shifts to the European level, which will have a
larger impact. It is possible that there will be objections to such a change, especially the
third option where more congestion income is managed on this level.
Summary
Overall, do nothing is not considered an appropriate response, as it does not address the
deficiencies in the current legislation. Changing the current arrangements will not only
increase the incentives on TSOs, but also on Member States and NRAs
i.e. there is a
sum of money that must be spent on interconnection in some form. Whilst tariffs can
always be used to fund such developments, there are counter-incentives, i.e. to keep
tariffs lower by limiting development to that which is strictly necessary as opposed to
being of longer-term benefit and of benefit to the EU internal market as a whole.
Option 1 is the least change, and the most flexible. However, due to this flexibility it is
also the option which could see the least amount of money redirected from being used
when calculating tariffs or from internal accounts towards projects that increase
interconnection capacity. Option 3 would be a significant change and takes away all
national-level decision-making on new investment using congestion income. This may be
less proportionate than allowing some national autonomy, at least in the first instance if it
achieves broadly the same ends. Option 2 would see the same financial potential for new
network investments that increase interconnection capacity
i.e. up to EUR 1.14 billion
per annum. It is therefore considered the most proportionate response to achieve the ends
sought.
4.4.6.
Subsidiarity
The use of congestion income by TSOs has already been addressed at EU-level as part of
the Third Package. The issue is very much one of a cross-border nature, as the majority
of congestion income is raised on infrastructure that crosses Member State borders. A
common approach across the EU is necessary to ensure a level-playing field between
Member States and leaving the issue at national, or bi-lateral, level risks inconsistent
application.
35% of congestion income was used on average over 2014 and 2015 to reduce tariffs,
despite the increase of cross-border trade in electricity between most EU Member States
and the growing need to strengthen the physical connection of electricity markets. Also,
maintaining grid stability becomes more challenging as increasing shares of variable
renewables enter the energy mix; higher interconnection levels could decrease the
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necessity for redispatch and lead to lower network tariffs. These issues, given their cross-
border impacts, can only be dealt with at an EU-level.
Given that the most common use of congestion income does not seem to address the
current needs of grid development and maintenance, further EU action is necessary to
ensure that there is an increase of the proportion of congestion income spent on
maintaining or increasing interconnection.
4.4.7.
Stakeholders' opinions
Whilst there was not a specific question in the energy market design consultation on
congestion income, and many respondents did not comment on the issue, some did
express views. For example, comments included:
"… It should be a common European interest to reduce or remove permanent
bottlenecks between countries within the EU. Primarily it should be done by using the
congestion incomes for investments instead of simply managing the congested
transmission lines. There is no need for separate capacity pricing for the energy only
markets."
"At the moment, income from congestion management shall be used to mitigate the
bottleneck or decrease the end user tariffs. However clear mechanism for setting up
the financing of the new projects shall be in place (including needed change in
accounting standards and income tax rules). With the new investment the respective
bottleneck is dismissed and there is no further income from congestion management.
This makes the return on investment impossible."
"According to the Communication it is essential to achieve the previously established
target value of 10% for the interconnection of electricity networks, and its increase to
15%. To this end, the current effective EU regulation provides adequate support. At
the same time, according to the Commission’s concept the utilisation of fees
currently
charged for congestion management should be regulated in a manner which would
facilitate the development of the electricity system. We would be in a position to
support this concept if there is guarantee that once the target value has been
achieved by a Member State the revenues could still be used for other purposes as
well (e.g. tariff cuts)."
"…funds
[for cross-border redispatching]
could come from congestion rents which
are not possible to be attached to a border anymore in a flow-based world. This
common TSO income should be spent commonly on costly coordinated actions."
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5. D
ETAILED MEASURES ASSESSED UNDER
P
ROBLEM
A
REA
II, O
PTION
2(2) (
IMPROVED
ENERGY MARKETS
- CM
S ONLY WHEN NEEDED
,
BASED ON COMMON
EU-
WIDE
ADEQUACY ASSESSMENT
(
AND
O
PTION
2(3) (I
MPROVED ENERGY MARKET
, CM
S ONLY
WHEN NEEDED BASED ON COMMON
EU-
WIDE ADEQUACY ASSESSMENT
,
PLUS CROSS
-
BORDER PARTICIPATION
)
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5.1. Improved resource adequacy methodology
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5.1.1.
Summary table
Objective: Pan-European resource adequacy assessments
Option 0
Do nothing.
National decision makers would continue to
rely on purely national resource adequacy
assessments which might inadequately take
account of cross-border interdependencies.
Due to different national methodologies,
national assessments are difficult to
compare.
Stronger enforcement:
Commission would continue to face
difficulties to validate the assumptions
underlying national methodologies including
ensuing claims for Capacity Mechanisms
(CMs).
Option 1
Binding EU rules requiring TSOs to
harmonise their methodologies for
calculating
resource
adequacy +
requiring Member States to exclusively
rely on them when arguing for CMs.
Option 2
Binding EU rules requiring ENTSO-E to
provide for a single methodology for
calculating resource adequacy
+
requiring Member States to exclusively
rely on them when arguing for CMs.
Option 3
Binding EU rules requiring ENTSO-E to carry
out a single resource adequacy assessment for
the EU
+ requiring Member States to
exclusively rely on it when arguing for CMs.
Description
National resource adequacy assessments
would become more comparable.
In addition to benefits in Option 1, it
would make it easier to embark on the
single methodology.
Even in the presence of a single
methodology,
national
assessments
would not be able to provide a regional
or EU picture.
National TSOs might be overcautious
and not take appropriately cross-border
interdependencies into account.
Difficult to coordinate the work as the
EU has 30+ TSOs.
Most suitable option(s): Option 3
- this approach assesses best the capacity needs for resource adequacy and hence allows the Commission to effectively judge whether the proposed
introduction of resource adequacy measures in single Member States is justified.
Cons
Even in the presence of harmonised
methodologies
national
assessment
would not be able to provide a regional
or EU picture.
In addition to benefits in Options 1 & 2, it
would make sure that the national puzzles neatly
add up to a European picture allowing for
national/ regional/ European assessments.
Results are more consistent and comparable as
one entity (ENTSO-E) is running the same
model for each country.
It would potentially reduce the 'buy-in' from
national TSOs who might still be needed for
validating the results of ENTSO-E's work.
Pros
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5.1.2.
Description of the baseline
Based on perceived or real resource adequacy concerns
40
, several Member States have
recently introduced resource adequacy measures. These measures often take the form of
either dedicated generation assets kept in reserve or a system of market wide payments to
generators for availability when needed (Capacity mechanisms or 'CM's).
Figure 1: CMs in the EU
Strategic reserves for DK2
region from 2016-2018 (and
potentially from 2019-2020)
Strategic reserve (since 2007)
Capacity auction
(since 2014 - first delivery in
2018/19)
Capacity payment
(since 2007)
considering reliably options
Capacity requirements
(certification started 1 April
2015)
Capacity payment (since 2008)
Tendering for capacity
considered but no plans
Strategic reserve
(since 2004 ) - gradual phase-
out 2020 and considering a
permanent market system
after 2020
Debate pending
Strategic reserve
(from 2016 on, for 2 years,
with possible extension for 2
years)
Strategic reserve
(since 1 November 2014)
Reliability option
(first auction end 2016, first
delivery contracted capacity is
expected in 2021)
New Capacity Mechanism
under assessment by COMP
(Capacity payments from 2006
to 2014)
Capacity Payment (Since 2010
partially suspended between
May 2011 and December 2014)
No CM (energy only market)
CM proposed/under consideration
CM operational
Source: ACER 2015 Monitoring report
National resource adequacy assessments
To determine whether these concerns require the introduction of a CM, Member States
41
first need to carry out an assessment of the adequacy situation. Indeed, all Member States
that are part of DG COMP's Sector Inquiry on Capacity Mechanisms measure the
security of supply situation in their country by carrying out an adequacy assessment in
which one or more methodologies are applied that give an indication of the potential of
the generation fleet to meet demand in the system at all times and under varying
scenarios.
40
41
The sector inquiry has shown that a clear majority of public authorities expect reliability problems in
the future even though today such problems have been extremely rare in the past five years. In nine out
of ten Member States, no such problems have occurred at all. The only exception is Italy, where such
issues have arisen on the islands of Sardinia and Sicily which are not well connected to the grid on the
mainland. Although the Member States do not experience reliability issues at present, many Member
States are of the opinion that reliability problems are expected to arise in the coming five years.
In most countries, TSOs are the responsible bodies for monitoring and reporting on long-term resource
adequacy. Other responsible institutions are NRAs or governments In the UK, the medium and long
term resource adequacy assessments are carried out by the NRA and government respectively. In
Estonia, the long term monitoring is managed by the government.
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The methodologies are however rarely comparable across Member States. Methods vary
significantly, for instance when it comes to the question whether to take into account
generation from other countries, but also regarding the scenarios and underlying
assumptions
42
.
The Council of European Energy Regulators (CEER)
43
performed a survey over
European countries showing that security of supply is dealt with at national level through
quite different approaches:
-
Assessing resource adequacy requires the definition of one or more
scenarios
that
can affect generation and demand projections. These scenarios are elaborated
according to different assumptions about load (typically high vs. low demand
scenario), and type and amount of future installed capacity (e.g. conservative or
baseline vs. high RES penetration scenario). Regarding the scenarios
44
used in the
different Member States, the methodologies differ greatly depending on the
targeted timeframe
45
and the majority of them do not seem to be consistent
throughout most of the national resource adequacy assessments.
Regarding
load forecast,
Member States base their projections on historical load
curves, with assumptions on the evolution of specific parameters. The most
exploited parameters are economic growth, temperature, policy, demography and
energy efficiency. The extent to which types of consumers are grouped to
appraise carefully different consumption patterns can be very different
46
.
Moreover demand response is largely not included as a separate factor in load
forecast methodologies, even though it may appear that it is indirectly included in
the projections through the effects it has had on the historical load curves
47
.
-
42
43
44
45
46
47
JRC (2016), "Generation adequacy methodologies review"
CEER (2014),
"Assessment of electricity generation adequacy in European countries"
In at least 6 countries (including Sweden, Romania, Malta, Finland and Norway) resource adequacy is
assessed against a single pre-defined baseline scenario. For the other cases (UK, France, the
Netherlands, Estonia, Hungary, Lithuania, Belgium, Spain, Ireland and Italy), several possible
scenarios are considered on the basis of different assumptions about load as well as type and amount of
future installed capacity, such as a conservative scenario, a baseline scenario a RES penetration
scenario, for example.
In at least 9 countries (France, Estonia, Malta, Hungary Lithuania, Belgium, Spain, Ireland and Italy)
the scenarios are compounded taking as a reference the short, medium and long-term horizons. In the
Netherlands and Finland, the long term is not considered, while in Sweden and Norway only the short-
term is taken into account. In Denmark, only the long-term scenario is considered. In the Czech
Republic and Switzerland, the only scenario considered is the very long term, while in Spain the latter
scenario completes the short, medium and long-term analyses. Finally, in Romania, no short-term
analysis is performed (only mid and long-term scenarios are considered).
In 10 national resource adequacy reports (the UK, France, Norway, Malta, Czech Republic, Hungary,
Lithuania, Ireland, Austria and Italy) more than one category of consumers (e.g. residential, industrial,
commercial, agriculture, etc.) serve as a basis for the forecasts; while in 4 reports (the Netherlands,
Estonia, Belgium and Sweden), load only is forecasted at an aggregate level.
Only 3 countries include demand response as a separate factor in their load forecast methodology i.e.
the UK, France and Spain. In Norway and Finland, the contribution from demand response is not
included as separate factor, but peak load estimation is based on actual load curves which include the
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-
Regarding
generation forecast,
the most important inputs are the information
received by those intending to build new generation and rules on how to consider
existing infrastructure. All Member States take projected investments into
account, sometimes with very heterogeneous sources and assumptions
48
. In
addition, there are also various ways generation from variable output (i.e.
intermittent RES) is modelled
49
; from no consideration at all, to precise hourly
estimations based on sophisticated data. It is commonly agreed that there is a
need to improve methodologies to better address how variable output impacts
adequacy.
With an increasing proportion of variable renewable resources, electricity systems
have become more complex. To address this increased complexity, some Member
States have replaced relatively simple, ‘deterministic’ assessment metrics
50
which simply compare the sum of all nameplate generation capacities with the
peak demand in a single one-off moment
by more complex
‘probabilistic’
51
models,
which are able to take into account a wide range of variables and their
behaviour under multiple scenarios. This includes not only state of the art weather
forecasts, but also factors in less predictable capacity sources such as the
contribution from demand response, interconnectors or renewable energy sources.
-
48
49
50
51
effect of demand response. Sweden does not consider demand response, and do not assume that
consumers respond to peak load in their analysis.
For instance, decommissioning (and mothballing) of investments is not systematically taken into
account. Most collected data come from generators, partly directly via the TSOs.
Some countries (Estonia, Romania, Malta and Denmark) still go with the approach of unavailable
capacity while there are also others like the Netherlands, Norway, Spain and Sweden, which take a
certain percentage as available generation. On the contrary, France and the UK go up to detailed
modelling based on climate data, hub heights (for offshore wind farms) and detailed coordinates for
the generation sites.
One of the simplest measures to determine the level of resource adequacy is the capacity margin. This
deterministic methodology simply expresses the relation between peak demand in the electricity
system and the total available supply, usually as a percentage. In only two of the eleven Member States
analysed in the sector inquiry, this relatively simple capacity margin is calculated. For instance in
2016, France had 104,480 MW of production installed capacity whereas peak demand during winter
2015/2016 was 84,700 MW; from that, one could say that France has approximately a 23% capacity
margin (RTE figures). Of course, no form of generation can always output its full nameplate capacity
with 100% reliability. Therefore, each source of input needs to apply a de-rating factor in order to
reflect its likeliness to be technically available to generate at times of peak demand (e.g. in Ofgem's
electricity capacity assessment, a combined cycled gas plant is assumed to be available 85% of the
time). In 2014, CEER found that 6 Member States were using de-rated capacity margins: Estonia,
Malta, Hungary, Belgium, Spain and Sweden.
Around half of the Member States of the sector inquiry carry out a 'probabilistic' calculation that can
be either expressed in LOLP, LOLE or EENS: (i) Loss of load probability (LOLP) quantifies the
probability of a given level of unmet demand at any particular point in time; (ii) Loss of load
expectation (LOLE) sets out the expected number of hours or days in a year during which some
customer disconnection is expected. For instance, French TSO RTE expects some customer
disconnection to happen during 1h45 over winter 2016-2017; (iii) Expected energy non served (EENS)
measures the total shortfall in capacity that occurs at the time when there are disconnections. EENS
makes it possible to monetise where VoLL has also been calculated.
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Nonetheless, these adequacy methodologies
52
still differ (deterministic vs.
stochastic).
-
Despite on-going developments, some assessments are still considering isolated
systems and/or developing ways to include interconnectors
53
. Others use non-
harmonised methodologies to consider cross-border capacity, with no cross-
border coordination foreseen. The availability of interconnection capacity is
mostly based on historical data (export and import flows during various periods
of time) and to lesser extent, on estimated data (e.g. market component such as
future prices estimations). Generation and load data correlations at supranational
levels are rarely considered
54
, and for country-wide modelling, the "copperplate
approach" prevails
55
.
It should be noted that monitoring and assessing resource adequacy is a very
complex process which requires defining robust concepts, criteria and procedures
in order to give a reference tool to decision-making bodies if problem are
encountered. In almost all EU countries, the body responsible for ultimately
ensuring resource adequacy is the national government. However, monitoring
responsibilities are usually shared among the TSO, the NRA and the government.
These responsibilities can evolve depending on the timeframe considered. For the
medium and long-term timeframes, TSOs are the responsible bodies for
monitoring and reporting in most Member States. Other responsible institutions
are NRAs or governments
56
. In most cases, the assessment is carried out yearly.
-
52
53
54
55
56
Half of the national studies are based on a 'probabilistic' approach (the UK, France, the Netherlands,
Finland, Romania, the Czech Republic, Lithuania, Belgium, Ireland, Italy) while six of them are based
on a deterministic approach (Estonia, Malta, Hungary, Belgium, Spain and Sweden). Denmark uses a
deterministic approach, but takes into account the outage percentage of power plants which is based on
both historical observations and Monte Carlo simulations.
The extent to which current resource adequacy reports take the benefits of interconnectors into account
varies a lot: 4 reports still model an isolated system (Norway, Estonia, Romania, and Sweden); 2
reports use both interconnected and isolated modelling (France and Belgium); 3 report methodologies
are being modified to include an interconnection modelling; 9 reports simulate an interconnected
system (UK, the Netherlands, Czech republic, Lithuania, Finland, Belgium and Ireland, while France
and Italy use both methods).
It is not obvious that national resource adequacy reports generally take interactions between generation
and demand profiles into account. Moreover, it seems that most reports do not consider correlated
data, which could be done (for example with the use of a common correlated climate database at
regional level, or a common methodology for load sensitivity to temperatures). One direct
consequence is that most reports do not intend to identify the impact on security of supply of potential
simultaneous severe conditions in different electricity systems.
In the process of assessing resource adequacy, transmission and distribution networks can be modelled
in a very different manner, from a highly realistic description of the technical parameters which
constrain the power flows in the system, to a simplified modelling where these networks are
considered as a copperplate grid. Some systems are said not to be subject to structural internal
congestions (including France and Romania).
In the UK, the medium and long term resource adequacy assessments are carried out by the NRA and
government respectively. In Estonia, the long term monitoring is managed by the government.
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Table 1: Deterministic vs probabilistic approaches to adequacy assessments
Source: European Commission based on replies to sector inquiry, see below for a description of capacity
margin, LOLP, LOLE, and EENS
ENTSO-E carries out an EU-wide resource adequacy assessments
In addition to resource adequacy assessments carried out by Member States, there are
also EU level rules foreseen by the Third Package (the Electricity Regulation) requiring
ENTSO-E to carry out a medium and long-term resource adequacy assessment (so-
called, Scenario Outlook and Adequacy Forecast or SO&AF) in order to provide
stakeholders and decision makers with a tool to base their investments and policy
decisions.
ENTSO-E is currently moving from a deterministic approach to a probabilistic approach
(sequential Monte-Carlo). This evolution will be done progressively and is expected to be
completely implemented by 2018. The first steps of the new methodology were carried
out in the latest published report so-called SO&AF 2015.
The ENTSO-E SO&AF 2015 presents the following characteristics/ limitations
57
:
-
ENTSO-E uses a deterministic assessment which calculates for each country
deterministic security of supply indicators (namely 'remaining capacity' and
'adequacy reference margin') only at particular points in time (the 3
rd
Wednesday
of each month on the 19
th
hour in the pan-European assessment or at national
peak load time in the national assessments). The report presents results for the
mid-term and long-term timeframes (5-year and 10 years ahead, respectively)
58
.
Regarding load forecast, there is no explicit modelling of demand-side response
in the SO&AF 2015 but is expected to be taken into account from 2017 onwards.
-
57
58
JRC Science for Policy Report (2016),
"Generation adequacy methodologies review"
Since 2011, ENTSO-E performs a SO&AF annually, with a time horizon of 15 years until SO&AF
2014 and 10 years in SO&AF 2015.
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-
Regarding generation forecast, the analysis is based on two different scenarios for
generation (conservative and best estimate). The conservative scenario considers
only new capacity if it is considered as certain and for the decommissioning, it
considers the official notifications but also additional criteria as for example,
technical lifetime of generators (additional criteria which are not considered in the
best estimate scenario). RES (wind and solar PV) are taken into account for the
first time in the SO&AF 2015 assessment by estimating their load factor (with a
Pan-European Climate database of 14 climatic years).
Regarding interconnection, the ENTSO-E SO&AF 2015 assessment only
considers import and export capacities for each country. There is no explicit
modelling of flow-based market coupling.
-
Voluntary initiatives to carry out regional resource adequacy assessments
Some Member States have voluntarily decided to cooperate and deliver a regional
resource adequacy assessment. This is the case of the seven TSOs in the Pentalateral
Energy Forum
59
('PLEF') who have decided to move away from country specific point in
time assessments to an integrated chronological probabilistic assessment. The new
methodology is based on harmonised and detailed input data to capture the main
contingencies
60
susceptible of threatening security of supply. This voluntary approach
developed by the PLEF TSOs is currently used as a test-lab for upgrading the ENTSO-E
methodology.
59
60
An inter-governmental initiative designed to promote collaboration on cross-border exchange of
electricity in Austria, Belgium, France, Germany, Luxembourg, the Netherlands, Switzerland.
These contingencies include outdoor temperatures (which result in load variations, principally due to
the use of heating in winter), unscheduled outages of nuclear and fossil-fired generation units, amount
of water resources, and wind and photovoltaic power production.
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Table 2: PLEF vs ENTSO-E approaches to adequacy assessments
PLEF
Approach
Scale
Probabilistic
Regional (at least direct
neighbours, up to
second degree
neighbours)
Current (NTC ) and
62
targeted (PTDF )
Loss of load (energy
duration, probability,
frequency,…),
capacity
margin
61
ENTSO-E
Current
Deterministic
National
simplified
regional
None on small scale,
maximum flows on
regional scale
Capacity margin
Targeted
Probabilistic
Pan European
First, NTC
Later, possibly flow-
based
Loss of load
Network representation
Security of supply
indicators
Uncertainty
Monte Carlo simulations
Additional margins
Monte Carlo simulations
considerations
Source: Artelys (2016), "METIS Study S4: Stakes of a common approach for generation and system
adequacy"
5.1.3.
Deficiencies of the current legislation
As highlighted in Section 7.3.2 of the Evaluation, resource adequacy is not addressed in
the Third Package. The Commission's current tool to assess whether government
interventions in support of resource adequacy are legitimate is State aid scrutiny. The
EEAG require among others a proof that the measure is necessary. However, the
framework does not allow the Commission to effectively judge whether there is a
resource adequacy problem in the first place.
To date, the need for CMs are based on national adequacy assessments and Member
States rely on them when arguying for CMs. However, national assessments are
undertaken in different ways across Europe. These assumptions may substantially differ
depending on the underlying assumptions made and the extent to which foreign
capacities as well as demand side flexibility are taken into account in calculations. For
example, the Council of European Energy Regulators (CEER) recommends to "take
into
account the potential benefit provided by interconnectors in national resource adequacy
analyses in a coordinated and consistent way across Member States"
63
. In addition,
CEER is of the opinion that "these
different procedures pose difficulties (especially for
neighbouring countries) as it is a challenge to understand the different procedures and
processes from one country to another"
64
.
61
62
63
64
Interconnectors are usually modelled as commercial flows with no network physical constraints, but
constrained by maximum net transfer capacities (NTC). In practice NTC values can vary quite often,
due to outages, maintenance and temperature affecting lines' physical properties.
Power Transfer Distribution Factor
CEER (2014),
Recommendations for the assessment of electricity generation adequacy
CEER report on
“Assessment of generation adequacy in European countries”
(published in 2014
)
http://www.assoelettrica.it/wp-content/uploads/2014/10/Ceer_GenerationAdequacyAssessment.pdf
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Art. 8 of the Electricity Regulation gives to ENTSO-E the responsibility for carrying out
a European resource adequacy outlook. It requires amongst others that the European
resource adequacy outlook should build on national resource adequacy outlooks prepared
by each individual TSO. Consequently the ENTSO-E assessment is rather a compilation
of national assessments than a genuine calculation based on raw data input. Also the
applied methodology needs a review in particular with regards to the input data and the
calculation method used. For example, the European Electricity Coordination Group
recommends that "The
improvements in the existing ENTSO-E methodology should focus
on the consistent treatment of variable RES generation and interconnectors"
65
.. In their
current form and granularity they are not suitable to assess whether certain Member
States are likely to face resource adequacy problems in the mid to long-term.
Further to the difference in approach, CEER highlights that "there
are also differences
between the System Outlook & Adequacy Forecast (SO&AF) undertaken by ENTSO-E
and the national assessments that occur due to different quality of data and a more
sophisticated approach in some countries"
66
.
All in all, neither national assessments nor ENTSO-E's European resource adequacy
outlook, in their current form a) appropriately inform investors, governments and the
wider public of the likely development of system margins and b) allow the Commission
to effectively judge whether the proposed introduction of resource adequacy measures in
single Member State is justified.
5.1.4.
Presentation of the options
Option 0 - BAU
National decision makers would continue to rely on purely national resource adequacy
assessments which inadequately take account of cross-border interdependencies. In
addition, due to different national methodologies, national assessments are difficult to
compare.
The Commission would continue to face difficulties to validate the assumptions
underlying national methodologies including ensuing claims for CMs.
Option 0+ stronger enforcement
As the current legislation foresees that national resource adequacy plans are the basis for
ENTSO-E to draw up its resource adequacy assessments, stronger enforcement is not a
viable option.
Some Member States (e.g. PLEF) have voluntarily decided to cooperate and deliver a
regional resource adequacy assessment. However, the PLEF geographically covers only
65
66
Report of the European Electricity Coordination Group on The Need and Importance of Generation
Adequacy Assessments in the European Union,
Final Report, October 2013
CEER report on
“Assessment of generation adequacy in European countries”
(published in 2014)
http://www.assoelettrica.it/wp-content/uploads/2014/10/Ceer_GenerationAdequacyAssessment.pdf
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part of the EU electricity market and hence its role cannot go beyond that of a test-lab for
upgrading the ENTSO-E methodology. Indeed, without a common methodology for all
EU Member States, the Commission would continue to face difficulties to effectively
judge whether the proposed introduction of resource adequacy measures in single
Member States is justified.
Option 1
Binding EU rules requiring TSOs to harmonise their methodologies for
calculating resource adequacy + requiring Member States to exclusively rely on them
when arguing for CMs
Option 1 would require TSOs to harmonise their methodologies for calculating resource
adequacy and require Member States to exclusively rely on them when arguing for CMs.
TSOs would have to cooperate to upgrade their methodologies based on probabilistic
calculations, with appropriate coverage of interdependencies, availability of RES and
demand side flexibility and availability of cross-border infrastructure in times of stress.
In this option, Member States would be responsible for carrying out the assessment.
Option 2 - Binding EU rules requiring ENTSO-E to provide for a single methodology for
calculating resource adequacy + requiring Member States to exclusively rely on them
when arguing for CMs
Option 2 would require ENTSO-E to provide for a single methodology for calculating
resource adequacy and require Member States to exclusively rely on them when arguing
for CMs. The ENTSO-E methodology should be upgraded based on propabilistic
calculations
67
and should appropriately take into account foreign generation, RES and
demand response.
In this option, Member States would be responsible for carrying out the assessment based
on the ENTSO-E methodology & coordination.
Option 3 - Binding EU rules requiring ENTSO-E to carry out a single resource adequacy
assessment for the EU + requiring Member States to exclusively rely on it when arguing
for CMs
Option 3 would require ENTSO-E to carry out an EU-wide resource adequacy
assessment and Member States to exclusively rely on it when arguing for CMs. In other
words, this would mean that, ENTSO-E would be required to not only provide for the
methodology (similar to Option 2) but also carry out the assessment. The ENTSO-E
assessment should have the following characteristics:
i.
ii.
It should cover all Member States
It should have a granularity of Member State/ bidding zone level to enable the
analysis of national/ local adequacy concerns;
67
The PLEF approach could serve as a pioneer for applying the advanced methodology for a wider
perimeter.
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iii.
iv.
v.
vi.
vii.
It should apply probabilistic calculations that consider dynamic characteristics of
system elements (e.g. start-up and shut-down times, ramp up and ramp-down
rates…)
68
It should calculate resource adequacy indicators for all countries (LOLE, EENS,
etc.)
It should appropriately take into account foreign generation, interconnection
capacity, RES
69
, storage and demand response
The assessment should be carried out every year
Time span of 5-10 years
It should be noted that under this option each Member State would be allowed to carry
out their national resource adequacy assessment if they wish to but they would not be
able to rely on these results when arguing for CMs.
5.1.5.
Comparison of the options
Contribution to policy objectives
Under
Option 0,
proposed CMs would be based on national resource adequacy
assessments and projections. National assessments may substantially differ depending on
the underlying assumptions made and the extent to which foreign capacities as well as
demand side flexibility and variable renewable generation
70
are taken into account in
calculations. Some countries even use deterministic methodologies that are obsolete (they
do not consider the stochastic nature of forced outages and variable renewable
generation). In addition, these national assessments are often not in line with the current
EU-wide assessment carried out by ENTSO-E. All in all, this approach reinforces the
national focus of most mechanisms and prevents a common view on the adequacy
situation. Remaining in the
status quo
may therefore lead to significant capacity
overinvestments. In consequence, it creates more uncertainty in neighbouring countries
as each Member State takes individual actions in putting in place CMs.
In
Option 1,
proposed CMs would still be based on national resource adequacy
assessments but these would adopt harmonised methodologies including input data. The
assessments would thus become more comparable across Member States. However, even
though this approach is an improvement compared to Option 0, it seems likely that
Option 1 would still lead to significant capacity overinvestments. Although this option
provides a minimum harmonization, the implementation time will take longer as some
Member States current methodologies are far from the target one. An entity or body
needs to assure that the harmonized methodology is properly implemented and check the
consistency of the results across countries. This option can produce significant delays.
68
69
70
This means considering flexibility issues, temporal constraints and a realistic evaluation of the
expected role of interconnectors.
National but also foreign RES should be considered as the IEM and the interconnection capacity are
the basis for a more and better integration of RES allowing a higher capacity factor for RES. The same
can apply to storage.
Some countries still assume zero capacity value for wind and PV. Countries that do not assume a zero
value differ on the methodology to estimate the capacity value of RES.
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Option 2
would make it easier to embark on a single methodology. Moreover, this
approach is likely to result in less over-investment in power infrastructure. However, it
would be difficult to coordinate the work of the 30+ TSOs in Europe. In addition,
national TSOs might be overcautious and not take appropriately into account cross-
border interdependencies. Even in the presence of a single methodology, national
assessments would not be able to provide an effective regional or EU picture.
71
Indeed,
national interests could still play a role in the manner in which the assessments are done.
There is a risk that Member States would deviate from the single methodology when
implementing it which means that an enforcement and monitoring mechanism should be
provided for.
Option 3
would most likely be the best option to reach the set objectives as it would
make sure that the national puzzles neatly add up to a European picture allowing for
national/ regional/ European assessments. A major advantage is that ENTSO-E has
already been carrying out an EU-level resource adequacy assessment based on the Union
legislation. By requiring ENTSO-E to carry out the assessment, Option 3 appears to be
appropriate to overcome the main obstacles that prevent Option 1 and 2 from being
effective. Indeed, there would be less room for Member States to deviate in the
implementation of the single methodology. This would favour neutrality as it would
avoid national interests playing a role in the manner in which the assessments are done.
Efficiencies would arise from a reduced need for coordination between Member States
and a reduced need for oversight during the implementation of the methodology by the
Member States. As a drawback, Option 3 would potentially reduce the 'buy-in' from
national TSOs who might still be needed for validating the results of ENTSO-E's work.
All in all, this option would best assess the capacity needs for resource adequacy and
hence allow the Commission to effectively judge whether the proposed introduction of
resource adequacy measures in single Member States is justified.
Key economic impacts
An expert study carried out using METIS
72
assesses the benefits of cooperation for
resource adequacy. The study highlights that significant capacity savings can be obtained
from a European approach to security of supply with respect to a country-level resource
adequacy assessment. The reasons for these savings is that Member States have different
needs in terms of capacity with peak demands that are not necessarily simultaneous.
Therefore, they can benefit from cooperation in the production dispatch and in
investments.
71
72
For example the extent to which Member States can rely on each other for contributions to their own
security of supply depends, among other things, on the likelihood of scarcity situations occurring
simultaneously in those Member States. Even if Member States calculate their resource adequacy
assessment based on a single methodology it cannot be ensured that they arrive at exactly at the same
outcomes except if all Member States share all data sets generated by the other and if they carry out
exactly the same computational steps using those data sets.
"METIS
Study S16: Weather-driven revenue uncertainty for power producers and ways to mitigate it",
Artelys (2016).
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The model jointly optimises peak capacities for two reference cases for EuCO27
73
without cooperation (capacities are optimised for each country individually, as if
countries could not benefit from the capacities of their neighbours) vs. with cooperation
(capacities are optimised jointly for all countries, taking into account interconnection
capacities (NTCs).
In both options, capacity dimensioning has the following characteristics: (i) removal of
peak fleets (CCGT, OCGT and oil) to avoid excessive overcapacity); (ii) Other units are
kept (including nuclear, coal and lignite), which creates overcapacity for CZ, SK and
BG; (ii) Optimisation of gas and peak fleats (modeled as OCGT) with VOLL = 15k
EUR/MWh and peak annual price = 60k EUR/MW/year.
The difference in installed capacity between the two cases reveals how much savings
could be made from cooperation in investments.
Results show that almost 80 GW of capacity savings (see figures 2 and 3) across th EU,
which represents 31% of the installed gas capacities, can be saved with cooperation in
investments. This represents a gain of EUR
4.8 billion per year
of investments.
It should be noted that this figure does not assess at which stage Member States are
currently (i.e. whether some Member States already benefit from the capacities of their
neighbours), as the benefits have already been reaped by some. It should also be noted
that
this figure does not include savings on production dispatch,
which could lead to
much higher monetary benefits.
73
The scope of the model comprises EU28 + (CH, NO, BA, MK, ME, RS) and 50 years of weather data.
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Figure 2
Capacity savings for METIS EuCO27 in GW
Source: METIS
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Figure 3
Capacity savings for METIS EuCO27 in % of demand
Source: METIS
The main reasons for these capacity savings are twofold: (i) variability of peak demand
across Europe and (ii) variability of weather conditions (and consequently of RES
generation profiles) across Europe.
-
Variability of power demand profiles across Europe: Energy end use practices are
different and the deployment of equipement using electricity (for instance
electrical heating) varies across Member States. In particular, the sensitivity of
Member States national demand with regards to temperature varies from one
country to the other. Moreover, low temperature events do not occur at the same
time in all Member States
74
. As a consequence, the aggregated European demand
peak is lower than the sum of all national demand peaks (which do not occur at
the same time). A European electric system with cooperation in capacity
dimensioning would therefore face a lower capacity need
defined by the
aggregated European demand peak
than a set of isolated national systems,
74
For instance, extreme temperature conditions are often not correlated between Western Europe and
Northern Europe (Norway, Sweden, Finland and Estonia).
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which would require a global generation capacity as high as the sum of national
peak demand.
Figure 4
illustration of cooperation in variability of peak demand across Europe
(based on ENTSO-E v3 scenario)
Source: METIS
-
Variability of RES generation profiles: Despite geographical correlations at the
regional scale, different climatic regimes produce different weather conditions
across Europe, which often compensate one another. This influences the RES
generation profiles. Indeed, aggregating European RES generation profiles leads
to higher load factors for RES than single country RES load factors.
Figure 5
illustration of cooperation in variability of RES generation across Europe
(based on ENTSO-E v3 scenario i.e. high RES scenario)
Source: METIS
Impact for businesses and public authorities
The
administrative costs
75
are expected to be marginal compared to the economic
benefits that would be reaped. ENTSO-E currently employs two FTEs to carry out its
resource adequacy assessment and has a working group of 10 FTEs from national TSOs.
In addition, we assume approximately 100 FTEs working on national resource adequacy
75
The economic costs linked to resource adequacy assessments are based on own estimations, resulting
from discussions with stakeholders and experts.
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assessments in TSOs across Europe (Option 0). Option 1 is assumed to require require
20-25 additional FTEs for coordinating the harmonisation of national assessments. It is
likely that Option 2 would be slightly less human intensive
only 15-20 additional FTEs
would be needed. Under Option 3, it is assumed that the same amount of FTEs would be
needed as in Option 2 but these would be employed by ENTSO-E. In monetary terms,
this can be translated into 2-3 million euros annually in terms of personnel costs for
Option 3. In addition, IT costs are equally likely to be small. For Option 3, IT costs are
assumed to be in the range from 2-3 million euros per year as ENTSO-E would need
more calculatory power that has IT implications. For options 1 and 2, they are likely to
be lower than for Option 3 as TSOs across Europe have already developed their own IT
systems. All in all, the estimated administrative costs of ENTSO-E providing for a single
methodology and carrying out the assessment (Option 3) would range from
4 to 6
million euros per year.
This is marginal compared to the estimated benefits presented
above.
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Table 3: Comparison of the Options in terms of their effectiveness, efficiency and
coherence of responding to specific criteria
Option 0:
No
further action
Option 1:
Harmonisation of
national
assessments
Option 2:
ENTSO-
E provides for
single
methodology,
Member States
carry out the
assessment
Option 3:
ENTSO-
E provides for
single methodology
and carries out the
assessment
Quality of the
methodology
--
No progress or
uncertain progress
as it depends on
Member State
independent
initiatives
-
Unclear which
processes to be
used
-
Each Member State
carries out its own
assessment
0
Progress remains
limited as only
harmonisation
++
Efficient as there is
a single
methodology
Use of
established
institutional
processes
+
Can build upon
established
processes
-
Each Member State
carries out its own
assessment
-
Higher capacity
savings due to
different treatment
of cross-border
capacity
0/+
Can partially build
upon established
processes
0/-
Each Member State
carries out its own
assessment based
on ENTSO-E
methodology
+
Higher capacity
savings as single
methodology
Efficient
organisational
structure
++
Coherence as
ENTSO-E runs the
same model for all
Member States and
the pan-European
assessments. Input
and output data are
more coherent.
-
Requires building
up new processes
(ENTSO-E to carry
out the assessment)
++
Efficient as
ENTSO-E carries
out the assessment
for all Member
States
++
Highest capacity
savings as single
methodology and
calculation
Capacity
savings
--
Low capacity
savings
The assumptions are based on the Market Design Initiative consultations and other
meetings with stakeholders
In summary:
-
Option 0, "No further action": will likely lead to significant over-investments and
hence will fall short in providing the adequate level of security of supply for
Europe for any given provision cost level.
Option 1, "Harmonisation of national assessments": is likely to be more efficient
than Option 0, but cannot be expected to fully meet the specific objectives.
Option 2, "ENTSO-E providing for a single methodology but Member States
carrying out the assessments": is likely to lead to less overinvestment.
Nonetheless, national interests could still play a role in the way in which the
assessments are done.
Option 3, "ENTSO-E providing for a single methodology and carrying out the
assessments": seems, according to the assessment of the options, to be the most
appropriate measure for assessing generation adequacy assessment.
-
-
-
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5.1.6.
Subsidiarity
The
subsidiarity
principle is fulfilled given that the generation adequacy challenges the
EU power system is facing cannot be optimally addressed based on national adequacy
assessments as is currently the case, as foreign contribution to national demand might not
be sufficiently taken into account. This can be the case because national assessments
apply different assumptions, calculatory approaches and data input. This is why it would
be best suited to require ENTSO-E to carry out a single updated generation adequacy
assessment for the EU based on a revamped methodology and high quality and granular
data input from TSOs including requiring Member States to exclusively rely on it when
arguing for CMs.
Requiring ENTSO-E to carry out a single generation adequacy assessment for the EU
would also be in line with the
proportionality
principle given that the total capacity
requirements for ensuring the same level of security of supply will be lower than in the
case of national adequacy assessments. This will strengthen the internal market by
making sure that resources are deployed and utilised efficiently across the EU.
5.1.7.
Stakeholders' opinions
Replies to the public consultation on the Market Design Initiative
A majority of stakeholders (34%) is in favour of sticking to an "energy-only" market,
possibly with a strategic reserve. Many generators and some governments disagree and
are in favour of market-wide CMs (in total 22% of stakeholders replies). Many
stakeholders (31%) share the view that properly designed energy markets would make
capacity mechanisms redundant (21% disagree).
There is almost a consensus amongst stakeholders on the need for a more aligned method
for
generation adequacy assessment
(73% in favour, 2% against). A majority of
answering stakeholders (47% of all stakeholders) supports the idea that any legitimate
claim to introduce CMs should be based on a common assessment. When it comes to
geographical scope of the harmonized assessment a vast majority of stakeholders (86%)
call for regional or EU-wide adequacy assessment while only a minority (20%) favour a
national approach.
Most of the stakeholders including Member States agree that a regional/European
framework for CMs are preferable. Member States, however, might want to keep a large
degree of freedom when proposing a CM. They might claim that beyond a revamped
regional/ EU generation adequacy assessment there is legitimacy for a national
assessment based on which they can claim the necessity of their CM.
Sensibilities
The CEER claims that "security
of supply is no longer exclusively a national
consideration, but it is to be addressed as a regional and pan-European issue"
and that
"generation
adequacy needs to be addressed and coordinated at regional and European
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level in order to maximise the benefit of the internal market for energy".
As a conclusion
to their survey, the CEER published recommendations
76
that emphasize the need for the
implementation of a single harmonised methodology. The PLEF has already used such a
common approach in a recent security of supply study
77
. In addition, ENTSO-E's target
methodology is announced to be "fully
in line with the methodology developed by the
TSOs of the PLEF"
78
.
EFET
79
is of the opinion that "the
current 'national approach' potentially leads to an
over procurement of capacity as Member States do not appropriately take into account
what capacity is available outside of their borders. As a medium step, regional
assessments based on clusters of countries that are highly interconnected can be
efficient, as they will effectively pool resources over a wider area. The ENTSO-E SO&AF
reports are a first step in the direction of a European approach to adequacy assessment.
However, the reports so far only consolidate the analysis of individual TSOs for their
respective control area/country. Market participants still expect a truly European
adequacy assessment from ENTSO-E, and national regulators should support the
requests of ACER and the European Commission in that regard."
On the ENTSO-E methodology, Wind Europe