kom (2016) 0863 - Ingen titel

Europaudvalget 2016
KOM (2016) 0863
Offentligt

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}

kom (2016) 0863 - Ingen titel

TABLE OF CONTENTS

4. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA II, OPTION 2(1);

(IMPROVED ENERGY MARKETS, NO CMS) .................................................................. 209

4.1. Removing price caps...................................................................................................................... 209

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

ROBLEM

REA

II,

OPTION

2(1);

(

IMPROVED

NERGY

ARKETS

)

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

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)

. 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

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

, 22

and 23

September 2015

Source: Belpex, EEX, APX

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Figure 4

–

Intraday prices in Belgium on 21

, 22

and 23

September 2015

Source: Belpex

Figure 5

–

Imbalance prices in Belgium on 21

, 22

and 23

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

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

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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"…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. "

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."

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."

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

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

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

. Overall, the

total welfare loss due to loop flows was estimated to be around 450 million euros in 2014

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)

, 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

. More specifically, once a review is launched

, TSOs are to

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

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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

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

. 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"

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.

Phillips, Nodal Pricing Basics, Independent Electricity Market Operator,

http://www.ieso.ca/imoweb/pubs/consult/mep/LMP_NodalBasics_2004jan14.pdf

Repowering markets

available

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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"

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

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

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

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

"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

to around 800

million euros

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

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

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

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

and

sufficiently in advance of their entry into force

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

. This regulation sets down limits on the

average annual transmission charges that can be applied in each Member States to

electricity producers

. 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

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

, 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

' 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

24 "

Art 37(1)(a)

Art 37(6)(a)

Commission Regulation (EU) No 838/210 of 23 September 2010 on laying down guidelines relating to

the inter-transmission system operator compensation mechanism and a common regulatory approach to

transmission charging,

OJ L 250 24.09.2010, p5-11

0-2 EUR /MWh in Romania; 0-2.5 EUREUR /MWh in UK and Ireland; 0-1.2 EUR/MWh in Denmark,

Sweden and Finland; and 0-0.5 EUR/MWh in all other Member States.

Transmission tariff harmonisation supports competition",

a report prepared for Energy Norway, May

2013

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

. 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.

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

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

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

. 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

, TSO surplus

, payments by consumers

and producer

surplus

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

" Transmission Tariffs and Congestion Income Po6licies",

ECN, DCision, Trinomics (Intermediate

Report)

Generation OPEX + Generation CAPEX + Fixed O&M + Transmission Investment

G-charge payments + Congestion income - Transmission CAPEX

Payments consumers make for their electricity use, i.e. electricity use (in MWh) x electricity price (in

Euro/MWh)

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

. With regards to grid

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

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

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

. 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.

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

, 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."

"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

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).

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

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

. 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

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

ROBLEM

REA

II, O

PTION

2(2) (

IMPROVED

ENERGY MARKETS

- CM

S ONLY WHEN NEEDED

BASED ON COMMON

EU-

WIDE

ADEQUACY ASSESSMENT

(

AND

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

, 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

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.

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

The Council of European Energy Regulators (CEER)

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

used in the

different Member States, the methodologies differ greatly depending on the

targeted timeframe

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

. 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

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

. In addition, there

are also various ways generation from variable output (i.e. intermittent RES) is

modelled

; 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

–

which simply compare the sum of all nameplate generation capacities with the peak

demand in a single one-off moment

–

by more complex

‘probabilistic’

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.

For instance, decommissioning (and mothballing) of investments is not systematically taken into account.

Most collected data come from generators, partly directly via the TSOs.

Some countries (Estonia, Romania, Malta and Denmark) still go with the approach of unavailable

capacity while there are also others like the Netherlands, Norway, Spain and Sweden, which take a

certain percentage as available generation. On the contrary, France and the UK go up to detailed

modelling based on climate data, hub heights (for offshore wind farms) and detailed coordinates for the

generation sites.

One of the simplest measures to determine the level of resource adequacy is the capacity margin. This

deterministic methodology simply expresses the relation between peak demand in the electricity system

and the total available supply, usually as a percentage. In only two of the eleven Member States analysed

in the sector inquiry, this relatively simple capacity margin is calculated. For instance in 2016, France

had 104,480 MW of production installed capacity whereas peak demand during winter 2015/2016 was

84,700 MW; from that, one could say that France has approximately a 23% capacity margin (RTE

figures). Of course, no form of generation can always output its full nameplate capacity with 100%

reliability. Therefore, each source of input needs to apply a de-rating factor in order to reflect its

likeliness to be technically available to generate at times of peak demand (e.g. in Ofgem's electricity

capacity assessment, a combined cycled gas plant is assumed to be available 85% of the time). In 2014,

CEER found that 6 Member States were using de-rated capacity margins: Estonia, Malta, Hungary,

Belgium, Spain and Sweden.

Around half of the Member States of the sector inquiry carry out a 'probabilistic' calculation that can be

either expressed in LOLP, LOLE or EENS: (i) Loss of load probability (LOLP) quantifies the probability

of a given level of unmet demand at any particular point in time; (ii) Loss of load expectation (LOLE)

sets out the expected number of hours or days in a year during which some customer disconnection is

expected. For instance, French TSO RTE expects some customer disconnection to happen during 1h45

over winter 2016-2017; (iii) Expected energy non served (EENS) measures the total shortfall in capacity

that occurs at the time when there are disconnections. EENS makes it possible to monetise where VoLL

has also been calculated.

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demand response, interconnectors or renewable energy sources. Nonetheless, these

adequacy methodologies

still differ (deterministic vs. stochastic).

Despite on-going developments, some assessments are still considering isolated

systems and/or developing ways to include interconnectors

. 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

, and for country-wide modelling, the "copperplate approach"

prevails

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

. In most cases, the assessment is carried out yearly.

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

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

Wednesday

of each month on the 19

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)

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,

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

('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

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

) and

targeted (PTDF

)

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

Additional margins

considerations

simulations

Source: Artelys (2016), "METIS Study S4: Stakes of a common approach for generation and system

adequacy"

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"

. 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"

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"

.. 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"

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

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

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:

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…)

It should calculate resource adequacy indicators for all countries (LOLE, EENS,

etc.)

It should appropriately take into account foreign generation, interconnection

capacity, RES

, storage and demand response

The assessment should be carried out every year

Time span of 5-10 years

iv.

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

are taken into account in

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.

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.

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,

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

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

–

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.

"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

. 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.

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

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

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:

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

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

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

. In addition, ENTSO-E's target methodology is

announced to be "fully

in line with the methodology developed by the TSOs of the PLEF"

EFET

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

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."

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

and the EEAG

require among others that such mechanisms are open and allow for the

participation of resources from across the borders. There is no reason to

believe that the EEAG framework is not enforced. To date, however,

there are not many practical examples of such cross-border schemes.

As the conclusion of individual cross-border arrangements depend on the

involved parties' willingness to cooperate it is likely that this option will

cement the current fragmentation of capacity mechanisms. Arranging

cross-border participation on individual basis is likely to involve high

transaction costs for all stakeholders (TSOs, regulators, ressource

providers).

Most suitable Option(s): Options 1 and 2

It would reduce complexity and the administrative impact for

market participants operating in more than one Member

States/bidding zone.

It would remove the need for each Member State to design a

separate individual solution

–

and potentially reduce the need for

bilateral negotiations between TSOs and regulators.

It would preserve the properties of market coupling and ensure

that the distortions of uncoordinated national mechanisms are

corrected and internal market able to deliver the benefits to

consumers.

It would be a cost for TSOs and regulators which would have to

agree on the rules and enforce them across the borders. These

costs would be lower than in Option 0 though.

Pros

In addition to the drawback of Option 1,

it would limit the choice of instruments.

Cons

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Description of the baseline

DG COMP's sector enquiry on Capacity Mechanisms found that cross-border participation

is not yet enabled in the majority of CMs, and with different Member States developing

different solutions for their already different national capacity mechanisms there is an

emerging risk of increasing fragmentation in the market.

The exclusion of foreign capacity from CMs reduces the efficiency of the internal market

and increases costs for consumers. The most damage is done if Member States make no

assessment of the possibility of imports when setting the amount of capacity to contract

through a CM (in a volume-based model) or setting the price required to bring forward the

required volume (in a price-based mechanism). In this approach (no

cross-border

participation),

there would be greater distortion of the signals for where new capacity

should be built, and an increase in overall system costs due to overcapacity. In addition,

CMs would fail to adequately reward investment in interconnection that allows access to

capacity located in neighbouring markets. The potential unnecessary costs of this

overcapacity has been estimated at up to 7.5 billion euros per year in the period 2015-

2030

Some Member States have attempted to address the problem by taking account of expected

imports (at times of scarcity) when setting the volume to contract in their capacity

mechanism (defined as

implicit participation)

This reduces the risk of domestic

overprocurement and recognises the value to security of supply of connections with the

internal energy market. However, implicit participation does not remunerate foreign

capacity for the contribution it makes to security of supply in the CM zone. If only domestic

capacity recieves capacity payments, there will be a greater incentive for domestic

investment than investment in foreign capacity or interconnectors resulting in less than

optimal investment in foreign capacity and in interconnector capacity.

The best approach to this would be

explicit participation

which means that the

contribution of imports to the CM zone must not only be identified, but the providers of

this foreign capacity need to be remunerated for the security of supply benefits that they

deliver to the CM zone.

This approach has been formalised in the Commission's Guidance on state interventions

and the EEAG which require among others explicit participation of foreign capacity in the

CM (EEAG 232).

However, putting in place a functioning explicit cross-border CM requires multiple

arrangements involving several parties (e.g. resource providers, TSOs, regulators). This is

a difficult exercise requiring willingness and cooperation from all parties which cannot be

taken for granted. This could explain why, to date, there are not many practical examples

of such cross-border schemes.

See Booz & co, 2013,

'Study on the benefits of an integrated European Energy market'

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Member States who have implemented an explicit cross-border scheme have taken

different approaches. Portugal, Spain and Sweden appear to take no account of imports

when setting the amount of capacity to support domestically through their CMs. In

Belgium, Denmark, France and Italy, expected imports are reflected in reduced domestic

demand in the CMs. The only Member States that have allowed the direct participation of

cross-border capacity in CMs are Belgium, Germany and Ireland.

Foreign plants were allowed to participate in the Belgian tender for new capacity, provided

that they would subsequently become part of the Belgian bidding zone even if

geographically located in another Member State.

In the Irish tender, foreign capacity could participate if it could demonstrate its contribution

to Irish security of supply

–

no foreign capacity was selected in the tender. In the existing

Irish capacity payments model, foreign capacity can benefit from capacity payments.

However, the method for enabling this participation involves levies and premiums on

electricity prices and is not therefore compatible with market coupling rules which require

electricity prices, not capacity premiums/taxes, to provide the signal for imports and

exports

None of the strategic reserves are open to generators located outside of the Member State

operating the reserve mechanism; except for the German network reserve which contracts

capacity outside of Germany provided that it can contribute to alleviating security of

supply problems in Southern Germany through re-dispatch abroad.

Despite the current lack of foreign participation, many Member States are trying to develop

cross-border participation in their mechanisms. France carried out last year a consultation

which outlined different options for the participation of interconnectors or foreign capacity

in the decentralised obligation scheme. Ireland published a consultation in December

options for cross-border participation in its planned mechanism. Italy is apparently

considering future foreign participation in its capacity mechanism. Since December 2015

the British capacity mechanism has included interconnectors with Britain, which can

participate as price takers in capacity auctions.

Deficiencies of the current legislation

The Commission's current tool to assess whether government interventions in support of

generation adequacy are legitimate is State aid scrutiny. The EEAG require among others

a proof that the measure is necessary, technological neutral and allows for explicit cross-

border participation. Beyond the requirements of the Commission's guidance on state

intervention and the EEAG, there is no European framework laying out the details of an

effective cross-border participation in capacity mechanisms.

This could explain why few Member States have developed cross-border schemes with

explicit participation, which means that (at best) they only

implicitly

take into account

foreign capacities. If Member States limit participation in a national mechanism only to

capacity providers located within their borders, and make overly conservative assumptions

Note however that the Irish capacity mechanism does operate across the UK and Irish border because of

joint market arrangements and a single bidding zone covering Ireland and Northern Ireland.

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about their level of imports they should expect, this will lead to distorted locational

investment signals and over-capacity in areas with capacity mechanisms. These distortions

can benefit incumbent market participants which will further reduce competition in the

long run.

Member States wanting to comply with the EEAG requirements have to individually

arrange, for each of their borders separately, the necessary cross-border arrangements

involving a multitude of parties including regulators, resource providers and TSOs.

Arranging cross-border participation on individual basis is likely to involve high

transaction costs for all stakeholders. This is also a difficult exercise requiring willingness

and cooperation from all parties which cannot be taken for granted.

When developing solutions for explicit participation of interconnectors and foreign

capacity to their CM, Member States need to address a number of policy considerations.

For example, an explicit participation model needs to identify:

Whether there should be any restriction on the amount of capacity that can

participate from each connected bidding zone;

What type of capacity product (obligations and penalties) should apply to foreign

capacity providers; and

Which foreign capacity providers are eligible to participate (DSR, generation,

storage).

It is therefore not surprising that 85% of market participant respondents and 75% of public

body respondents to the sector inquiry questionnaire felt that rules should be developed at

EU level to limit as much as possible any distortive impact of CMs on cross national

integration of energy markets.

The fact that cross-border participation is not yet enabled in the majority of CMs as

highlighted on p.30 of the Evaluation, and with different Member States developing

different solutions for their already different national CMs, there is an emerging risk of

increasing fragmentation in the market.

Presentation of the options

Option 0 - BAU

The Commission's Guidance on state interventions

and the EEAG require among others

that such mechanisms are open and allow for the participation of resources from across the

borders.

The EEAG include the following requirements related to cross-border participation in a

generation adequacy measure:

ii.

Should take the contribution of interconnection into account (226);

Should be open to interconnectors if they offer equivalent technical performance

to other capacity providers (232)

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iii.

iv.

Where physically possible, operators located in other members states should be

eligible to participate (232);

Should not reduce incentives to invest in interconnection, nor undermine market

coupling (233).

As explained above, the EEAG requires among others explicit participation of foreign

capacity in the capacity mechanism (EEAG 232). However, Option 0 does not provide for

a European framework setting out harmonised rules of an effective cross-border

participation scheme.

Option 0+

Despite the EEAG requirements for Member States to individually arrange, for each of

their borders separately, the necessary cross-border arrangements, few Member States

have voluntraily collaborated to develop an effective cross-border scheme. This is a

difficult exercise requiring willingness and cooperation from all parties which cannot be

taken for granted.

Option 1 - Harmonised EU framework setting out procedures including roles and

responsibilities for the involved parties (e.g. resource providers, regulators, TSOs) with a

view to creating an effective cross-border participation scheme

Under this option there would be a requirement for Member States to allow for explicit

participation of foreign capacity in national CMs.

There would also be a harmonised EU framework setting out procedures including roles

and responsibilities for the involved parties (e.g. resource providers, regulators, TSOs)

with a view to creating an effective cross-border participation scheme. The framework

would:

Define the appropriate share of foreign participation (de-rating of resources);

Allocation of 'entry tickets' to foreign resource providers

;

Same remuneration principles for domestic and foreign resource providers;

No booking (or setting aside) of cross-border capacities for cross-border

participation;

The contribution foreign capacity makes to a neighbour's security of supply is provided partly by the

foreign generators or demand response providers that deliver electricity, and partly by the transmission

(interconnection) allowing power to flow across borders. Depending on the border, there can be a relative

scarcity of either interconnection or foreign capacity. To ensure the right investment incentives, the

revenues from the mechanisms paid to the interconnection and/or the foreign capacity should reflect the

relative contribution each makes to security of supply in the zone operating the CM. Where

interconnection is relatively scarce but there is ample foreign capacity in a neighbouring zone, the

interconnectors should thus receive the majority of CM. This would reinforce incentives to invest in

additional interconnection, which is the limiting factor in in this case. Conversely, where there is ample

interconnection but scarcity of foreign capacity, the foreign capacity should receive most of the capacity

remuneration. In this case, foreign capacity is the limiting factor that should receive additional

incentives.

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e) Contribution of foreign capacity in parallel scarcity situations

to be addressed by

de-rating factors;

f) No delivery obligation (only availability);

g) No adjustment of cross-border schedules;

h) No limitation of the participation of a capacity resource to a single CM where the

resource can contribute to security of supply in more than one CM zone.

More details regarding the harmonised EU framework

De-rating of resources:

De-rating of interconnectors and/or foreign capacity refers to an evaluation of the

expected actual contribution of a capacity provider on average, over the long-term, at times when it is

required. This issue is critical as conservative assumptions will lead to overcapacity, and overly generous

assumptions will potentially lead to unmet demand (and potentially reduced confidence in the value of

interconnection).

Entry-tickets to foreign resource providers:

Foreign capacity providers would have to acquire specific

"interconnection tickets" to allow them to explicitly participate in the CM. Foreign capacity bids to get access

to the capacity market via the interconnection, up to the level of available interconnection capacity. The

interconnection receives revenues from "interconnection tickets" auctioning. Foreign capacities receive

revenues at "local CM" clearing price. This would allow a priori a market-based split of value and the right

incentive for investments.

Same remuneration principles for domestic and foreign resource providers:

In principle, if the

allocation process for capacity contracts allows interconnector or foreign capacity to compete directly with

domestic capacity, the obligation and penalties faced by the interconnector or foreign capacity providers

should be the same as the obligations and penalties faced by the domestic capacity providers.

No booking of cross-border capacity for cross-border participation:

One of the basic features of capacity

mechanisms is that the participating resources (mainly generators) receive a payment for their availably in

times of expected system stress. Whether a participating resource actually generates electricity depends on

short-term market price signals (effectively intra-day and balancing market prices). This mechanism makes

sure that power flows to the area in Europe that needs it most. For example, if short-term prices in Belgium

turn out to be 2.000 EUR/MWh while prices around Belgium are only 250 EUR/MWh the market coupling

algorithm (and successive intra-day exchanges) will make sure that all available transmission capacities on

the Belgian border will be used to flow power into the country. The limiting factor to supply Belgium in

times of stress is (most likely) not the availability of generating assets in Europe but the relative scarcity of

transmission capacities towards Belgium. Setting aside transmission capacities for the purposes of cross-

border participation will therefore not improve the security of power supplies in Belgium but will only

interfere with the efficient functioning of power markets. Participation of resources from across the border

should therefore not be link to the effective delivery of electricity from that resource. Paying for capacity

(availability) across the borders can still make sense as this provides incentives to keep resources available

to produce if market prices signal so.

Contribution of foreign capacity in parallel scarcity situations to be addressed by de-rating factors:

practice, it is extremely unlikely that scarcity events will be perfectly correlated between two neighbouring

countries. So, to avoid a situation where overall less contribution by imports to security of supply is assumed

than is truly the case, a statistical judgement

–

de-rating of the interconnectors on each border to reflect

expected long-run average import capacity at times of scarcity

–

is needed for each capacity mechanism. The

The extent to which an interconnector can reliably provide imports to the countries it connects depends

not just on the line's technical availability but also on the potential for concurrent scarcity in the

connected markets. If zone A only has a winter peak demand problem and connected zone B only has a

summer peak demand problem, each may expect 100% imports from the other at times of local scarcity.

However, if countries A and B are neighbours with similar demand profiles and some similar generation

types, there may be some periods of concurrent scarcity where neither can expect imports from the other.

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amount of capacity demanded domestically should be reduced by this amount, and this capacity is then

available for allocation to foreign capacity providers.

No delivery obligation (only availability):

An availability cross-border product allows the internal market

to function unimpeded and avoids creating distortions to merit order dispatch that might be created with

delivery obligations. Moreover, an availability product provides an additional incentive for Member States

to correct regulatory failures and ensure their electricity prices reflect scarcity

–

which has further benefits

for market functioning as such prices provide a signal for investment in flexible capacity and enable demand

response. Lastly, establishing a relatively simple availability product

–

along with other common rules

–

makes cross-border participation much more readily implementable.

No adjustment of cross-border schedules:

Because of the potential for delivery obligations to create

distortions in neighbouring markets and the fact that anyway such obligations can only incentivise actions

which are likely to have a very limited effect on cross-border flows, delivery obligations are not appropriate

for interconnectors or foreign capacity.

No limitation of the participation of a capacity resource to a single CM where the resource can

contribute to security of supply in more than one CM zone:

Without this requirement explicit

participation is likely to lead to overcapacity which would be a worse outcome than implicit participation.

Option 2:

–

Option 1 + EU framework harmonises the main features of the capacity

mechanisms per category of mechanism (e.g. for market-wide capacity mechanisms,

reserves, …)

In addition to Option 1, the EU framework would harmonise the main features of the

capacity mechanisms per category of mechanism (e.g. for market-wide capacity

mechanism, reserves, etc.), such as the properties of capacity product to be offered, the

duration of the obligation, etc.

Comparison of the options

Contribution to policy objectives

Option 0

already requires explicit participation of foreign capacity in the CM under the

EEAG rules. However, the EEAG framework does not set out harmonised rules of an

effective cross-border participation scheme. This explains why few Member States have

developed cross-border schemes with explicit participation, which means that (at best) they

only implicitly take into account foreign capacities. If Member States limit participation in

a national mechanism only to capacity providers located within their borders, and make

overly conservative assumptions about their level of imports they should expect, this will

lead to distorted locational investment signals and over-capacity in areas with capacity

mechanisms, and an increase in overall system costs. As the conclusion of individual cross-

border arrangements depend on the involved parties' willingness to cooperate it is likely

that this option will cement the current fragmentation of capacity mechanisms. Arranging

cross-border participation on individual basis for each of a Member States borders is likely

to involve high transaction costs for all stakeholders (TSOs, regulators, ressource

providers). This is also a difficult exercise requiring willingness and cooperation from all

parties which cannot be taken for granted.

Option 1

would facilitate explicit cross-border participation as already required by EEAG

by providing an EU framework with roles and responsibilities of the involved parties. This

option would remove the need for each Member State to design a separate individual

solution

–

and potentially reduce the need for bilateral negotiations between TSOs. It

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would also reduce complexity and the administrative impact for market participants

operating in more than one zone. Hence, it is likely that an increased number of Member

States would implement an effective cross-border scheme. Explicit participation would

lower overall system costs as it corrects investment signals and enables a choice between

local generation and alternatives. On one hand, the capacity in a CM zone will bid lower

into the domestic CM as a result of access to revenues from electricity and capacity in

neighbouring zones. On the other hand, this will lead to more investment in capacity in a

non-CM zone, and in transmission to neighbouring CM zones, if capacity in a non-CM

zone has access to neighbouring capacity and energy prices. All in all, with the design

options of an EU framework chosen above, Option 1 is likely to better preserve operational

market efficiencies (e.g. market coupling) and ensure that the investment distortions of

uncoordinated national mechanisms are corrected and the internal market able to deliver

the benefits to consumers.

Option 2

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. At the same time there is a risk that it would limit the choice of instruments

and potentially the ability to answer a wider range of problems that capacity mechanisms

could address.

Key economic impacts

The economic impacts of the different options are analysed in the core document "Section

6 - Problem Area II".

Impact for businesses and public authorities

Although the cost of designing cross-border participation in CM depends to some extent

on the design of the CMs, an expert study

estimated that such cost corresponds roughly

to 10%

of the overal cost of the design of a CM

. In addition, they estimate costs

associated with the operation of a cross-border scheme i.e. additional costs if cross-border

participation is facilitated to amount to 6-30 FTEs

for TSOs and regulators combined.

TSOs and regulators have to check pre-qualification and registration (eligibility phase) and

ensure compliance i.e. monitoring, control, penalties (control/ compliance phase).

Market participants participating in a cross-border scheme would potentially have

additional costs of 0-3 FTEs.

The expert study found that providing for a common framework for cross-border

participation (Option 1) would actually reduce the cost of cross-border participation when

Thema (2016),

Framework for cross-border participation in capacity mechanisms (First interim report)

Costs in the design phase are one-time costs.

The same expert study also found that the overall cost of of the design are fairly small compared to the

overall cost of the CM (remuneration of the participation ressources).

FTEs in other phases refer to (annually) recurring costs.

There is a difference between a generator model for cross-border participation and an interconnector

model in relation to the costs. This difference can be explained by the number of participants and

jurisdictions. The more participants and countries participate, the greater the potential for increased

costs.

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compared with Option 0. This is because in Option 0 cross-border arrangements have to

be set up and operated based on indivdual arrangements which involve costs that can be

saved if these arrangements follow a template. For TSOs and NRAs, the study estimates

the cost saving for Option 1 to be 30% of eligibility costs and compliance costs compared

to Option 0.

In analogy to Option 1 we would expect that providing for a common template for capacity

mechanisms (Option 2) would actually reduce the design cost of CMs when compared with

Option 0 and Option 1. This is because in Option 0 and Option 1 CMs are designed

individually which involve costs that can be saved if the CM design follows a template.

For TSOs and NRAs, the study estimates the cost savings to be 50% of eligibility costs

and compliance costs compared to Option 0.

Table 1: Comparison of the Options in terms of their effectiveness, efficiency and

coherence of responding to specific criteria

Option 0:

do nothing (EEAG)

More chance of

distorted locational

signals and over-

capacity in zones with

Higher overall system

costs

Option 1:

EU framework for

cross-border

participation

Less chance of

investment distortions

due to effective cross-

border scheme

Option 2:

framework for cross-

border participation +

blueprint

Less chance of

investment distortions

due to effective cross-

border scheme

Investment distortions

due to uncoordinated

CMs

Lower overall system

Overall system costs

costs due to reduction in costs due to reduction in

CM auction price

Speed of

Individual XB

Harmonised XB

implementation

arrangements for each

arrangements across the arrangements across the

border

High administrative

Reduced complexity

Complexity and

impact for market

and administrative

administrative impact

participants operating in

impact due to

more than one zone

harmonised rules

The assumptions are based on the Market Design Initiative consultations and other meetings with

stakeholders

Subsidiarity

The

subsidiarity

principle is fulfilled given that the EU is best placed to provide for a

harmonised EU framework with a view to creating an effective cross-border participation

scheme. Member States currently take separate approaches to cross-border participation

including often not allowing for foreign participation or only implicitly taking into account

foreign contribution to own security of supply. As cross-border participation in CMs

requires neighbouring TSOs' and NRA's full cooperation, individual Member States might

not be able to deliver a workable system or only provide suboptimal solutions.

Providing for a framework on cross-border participation in capacity mechanisms would be

also in line with the

proportionality

principle given that it aims at preserving the

properties of market coupling and ensuring that the distortions of uncoordinated national

mechanisms are corrected and the internal market is able to deliver the benefits to

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consumers. At the same time, it removes the need for each Member State to design a

separate individual solution

–

and potentially reducing the need for bilateral negotiations

between TSOs and NRAs.

Stakeholders' opinions

Public consultation on the Market Design Initiative

Stakeholders clearly support a common EU framework for

cross-border participation

capacity mechanisms (52% in favour, 10% against). Most of the stakeholders including

Member States agree that a regional/European framework for CMs are preferable.

Similarly, Member States might instinctively want to rely more on national assets and

favour them over cross-border assets. It is often claimed that in times of simultaneous

stress, governments might choose to 'close borders' putting other Member States who

might actually be in bigger need in trouble.

Sensibilities

EFET

is of the opinion that "Member

States with a CM need to explicitly take into account

the contribution of foreign capacities. This will likely require advanced TSO-TSO

cooperation, and will require more complex arrangement at EU or regional level. EFET

therefore supports the establishment of EU rules in this domain. One note of caution

though: in no case should the cross-border participation to national CMs result in any

reservation of cross-border transmission capacity or alteration of cross-border flows from

the market outcomes".

Wind Europe

"acknowledges

the need for a common set of indicators and criteria for

cross-border participation, as this is a necessary condition for the existence of capacity

markets where needed."

[…] In addition, they "call

for a strong involvement of the

Commission to ensure that such a common European framework for cross-border

participation does not serve as a pretext for introducing potentially unneccesary CMs."

ACER and CEER

"fully

endorse that explicit participation of foreign capacity providers

into national CMs through a market-based mechanism should be allowed. In this respect,

[…]

a few important prerequisites need to be fulfilled to make explicit cross-border

participation possible and beneficial: a) TSOs are incentivised to make a sufficient and

appropriate amount of cross-border capacities available for cross-border trade

throughout the year(s); b) TSOs are not allowed to adjust, limit or reserve these cross-

border transmission capacities at any point in time, including in case of shortage situation;

and c) TSOs agree ex ante on the treatment of local/ foreign adequacy providers in case

of a widespread shortage situation (i.e. when a shortage situation affects at least two

countries simultaneously)."

EFET response to the public consultation on the Market Design Initiative, 2015

WindEurope response to the public consultation on the Market Design Initiative, 2015

ACER-CEER response to European Commission Capacity Mechanism Sector Inquiry, July 2016

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