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
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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
Summary table ............................................................................................................................. 209
Description of the baseline .......................................................................................................... 210
Deficiencies of the current legislation ......................................................................................... 215
Presentation of the options ......................................................................................................... 215
Comparison of the options .......................................................................................................... 216
Subsidiarity ................................................................................................................................... 217
Stakeholders' opinions ................................................................................................................. 218
4.2. Improving locational price signals ................................................................................................. 220
Summary Table ............................................................................................................................ 221
Description of the baseline .......................................................................................................... 222
Deficiencies of the current legislation ......................................................................................... 228
Presentation of the options ......................................................................................................... 229
Comparison of the options .......................................................................................................... 230
Subsidiarity ................................................................................................................................... 231
Stakeholders' opinions ................................................................................................................. 232
4.3. Minimise investment and dispatch distortions due to transmission tariff structures .................... 234
Summary table ............................................................................................................................. 235
Description of the baseline .......................................................................................................... 236
Deficiencies of the current legislation ......................................................................................... 238
Presentation of the options ......................................................................................................... 238
Comparison of the options .......................................................................................................... 240
Subsidiarity ................................................................................................................................... 244
Stakeholders' opinions ................................................................................................................. 245
4.4. Congestion income spending to increase cross-border capacity .................................................... 247
Summary table ............................................................................................................................. 248
Description of the baseline .......................................................................................................... 250
Deficiencies of the current legislation ......................................................................................... 253
Presentation of new measures/options....................................................................................... 253
Comparison of the options .......................................................................................................... 255
Subsidiarity ................................................................................................................................... 257
Stakeholders' opinions ................................................................................................................. 258
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) ................. 260
5.1. Improved resource adequacy methodology .................................................................................. 262
Summary table ............................................................................................................................. 263
Description of the baseline .......................................................................................................... 264
Deficiencies of the current legislation ......................................................................................... 270
Presentation of the options ......................................................................................................... 271
Comparison of the options .......................................................................................................... 272
Subsidiarity ................................................................................................................................... 279
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Stakeholders' opinions ................................................................................................................. 279
5.2. Cross-border operation of capacity mechanisms ........................................................................... 282
Summary table ............................................................................................................................. 283
Description of the baseline .......................................................................................................... 284
Deficiencies of the current legislation ......................................................................................... 285
Presentation of the options ......................................................................................................... 286
Comparison of the options .......................................................................................................... 289
Subsidiarity ................................................................................................................................... 291
Stakeholders' opinions ................................................................................................................. 292
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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
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.
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.
Cons
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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 domestic
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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, FRR
prices are capped to zero (downward regulation) and to the fuel cost of CCGT plus 40
1
https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/224028/value_lost_load
_electricty_gb.pdf
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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. The
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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.
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.
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
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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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.
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. 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
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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.
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.
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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.
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
"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
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-
-
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-
"…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. Improving locational price signals
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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.
Nodal pricing implies a complete,
fundamental overhaul of current grid
management and electricity trading
arrangements with very substantial
transition costs.
Cons
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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.
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
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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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.
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
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
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
8
9
10
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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.
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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:
"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
13
Annex I section 1.7
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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
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
.
14
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.
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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
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.
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
15
"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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to overcome the problems that block progress in the internal electricity market (e.g.
definition of fair bidding zones, effective cross-border curtailments)"
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
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
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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.
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 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
16
17
18
19
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
Around 280 million euros in the case of moving to 9 zones.
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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.
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
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.
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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).
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
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
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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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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.
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.
Cons
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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.
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
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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.
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
20
21
22
23
24 "
25
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
A Commission Regulation developed under procedures laid down in the Electricity Regulation.
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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.
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.
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."
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.
26
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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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
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
27
Excluding Austria and Belgium, who apply energy-based charges for ancillary services and/or losses
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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.
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 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)
85,082.2
TSO
surplus
2,102.3
Consumer
payments
226,821.0
Producer
surplus
138,455.7
28
" 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
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Option 0 (current
situation)
Option 1 (cap.-based
tariffs)
85,094.7
85,094.0
3,044.6
2,875.1
227,617.6
227,298.2
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 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.
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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. 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
33
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).
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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.
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
34
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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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 example to avoid
any discrimination between distribution-connected and transmission-connected generation
when setting or approving tariffs.
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.
35
E.g. changes to G-charges could be effected by amending the ITC regulation.
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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;
-
-
-
-
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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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.
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.
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.
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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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.
Figure 1 - Optimum interconnection capacity from a social versus private benefit
perspective
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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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.
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
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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the allowed rate of return may be considered too low to cover the risks, uncertainties or
other challenges involved.
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)
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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 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."
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.
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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.
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.
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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.
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.
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
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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
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.
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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) 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.
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.
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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
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.
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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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.
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.
Cons
Pros
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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
-
effect of demand response. Sweden does not consider demand response, and do not assume that
consumers respond to peak load in their analysis.
48
For instance, decommissioning (and mothballing) of investments is not systematically taken into account.
Most collected data come from generators, partly directly via the TSOs.
49
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.
50
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.
51
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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demand response, interconnectors or renewable energy sources. 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.
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,
-
-
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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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.
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
61
) and
targeted (PTDF
62
)
ENTSO-E
Current
Deterministic
National
simplified
regional
None on small scale,
maximum flows on
regional scale
Targeted
Probabilistic
Pan European
First, NTC
Later, possibly flow-
based
Network representation
Loss of load (energy
duration, probability,
Security of supply
Capacity margin
Loss of load
indicators
frequency,…),
capacity
margin
Uncertainty
Monte Carlo
Monte Carlo
Additional margins
considerations
simulations
simulations
Source: Artelys (2016), "METIS Study S4: Stakes of a common approach for generation and system
adequacy"
59
60
61
62
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.
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
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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
.
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
63
64
65
66
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
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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effectively judge whether the proposed introduction of resource adequacy measures in
single Member State is justified.
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
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
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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.
iii.
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;
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
iv.
v.
vi.
vii.
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.
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
67
68
69
70
The PLEF approach could serve as a pioneer for applying the advanced methodology for a wider
perimeter.
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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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.
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,
71
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.
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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.
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.
72
73
"METIS
Study S16: Weather-driven revenue uncertainty for power producers and ways to mitigate it",
Artelys (2016).
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, which would require a global
generation capacity as high as the sum of national peak demand.
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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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 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
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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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.
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,
-
-
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-
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.
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.
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
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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 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
80
is of the opinion that "most
national
adequacy assessments focus on the contribution of firm generation units, with little or no
consideration for the contribution of other energy sources such as demand-side response,
storage, imports/exports or renewables."
It recommends that "developing
a holistic
approach that systematically and realistically include renewables, demand response,
storage and interconnections' contribution to adequacy."
76
77
78
79
80
Recommendations for the assessment of electricity generation adequacy, CEER
Pentalateral Energy Forum [PLEF]
Support Group 2, Generation Adequacy Assessment
Energy Community Workshop: "Towards
Sustainable Development of Energy Community",
RES
integration: the ENTSO-E perspective
EFET answer to the public consultation on the market design initiative
Wind Europe, "Assessing resource adequacy in an integrated EU power system" (May 2016)
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5.2. Cross-border operation of capacity mechanisms
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Summary table
Objective: Framework for cross-border participation in capacity mechanisms
Option 0
Option 1
Do nothing.
Harmonised EU framework setting out procedures including
No European framework laying out the details of an effective cross- roles and responsibilities for the involved parties (e.g. resource
border participation in capacity mechanisms. Member States are likely to providers, regulators, TSOs) with a view to creating an effective
continue taking separate approaches to cross-border participation, cross-border participation scheme.
including setting up individual arrangements with neighbouring markets.
Option 2
Option 1 + EU framework harmonising
the main features of the capacity
mechanisms per category of mechanism
(e.g.
for
market-wide
capacity
mechanisms, reserves, …).
In addition to benefits in Option 1, it
would
facilitate
the
effective
participation of foreign capacity as it
would simplify the design challenge and
would probably increase overall
efficiency by simplifying the range of
rules market participants, regulators and
system operators have to understand.
Description
Stronger enforcement
The Commission's Guidance on state interventions
81
and the EEAG
require among others that such mechanisms are open and allow for the