FRENCH CAPACITY MARKET Report accompanying the draft rules

RTE Réseau de transport d’électricité SA shall not be liable for damages of any nature, direct or indirect, arising from the use of data and information contained in this document, including any operational, financial or commercial losses.

APRIL 9 2014

FRENCH CAPACITY MARKET Report accompanying

the draft rules  

4

SUMMARY

The principle: A mechanism to ensure security of supply

French law 2010-1488 of 7 December 2010 reforming the

organi sation of the electricity market (NOME Act), codified in arti-

cles L.  335-1 et seq. of the Energy Code, calls for the creation

of a capacity obligation scheme. It specifies that “each supplier

contributes, in accordance with the demand characteristics of its

customers, in terms of power and energy, to the security of elec-

tricity supply in continental France.”

Decree 2012-1405 of 14 December 2012 defines the general

organisational framework for the new scheme.

Obligations will be assigned to suppliers based on the actual

consumption of their customers during peak periods. To meet

its obligation, a supplier will have to secure capacity certifi-

cates, either by certifying the capacities it operates (generation

or demand-side capacities) or by purchasing certificates from

players that hold them. Individual obligations, defined based on

parameters established four years before the target delivery year,

will be updated to reflect the effective consumption data meas-

ured within the supplier's portfolio.

Capacity certificates will initially be issued by RTE to opera-

tors based on the projected contribution of their capacities to

reducing the shortfall risk during peak periods. Generators must

request certification for their capacities at least three years before

the target delivery year, while demand-side operators can submit

requests up until the start of the same delivery year. Availability

levels indicated in requests are compared with effective availabil-

ity and settlements are calculated to reflect imbalances.

The provisions proposed define a new market mechanism, regu-

lated by public authorities, through which holders of certificates

can trade them with obligated parties to enable the latter to meet

a legal obligation.

This mechanism is intended to provide a form of “insurance”:

operators are rewarded for the contributions their capacities

make to the power system by being available during periods of

tight supply. Starting four years before the delivery period, the

mechanism will generate economic signals complementing

those generated by the energy market.

The decree includes a detailed explanation of the principles to be

applied in certifying operators’ capacities, allocating obligations

to suppliers and organising capacity certificate trading along with

the related transparency mechanisms.

The principles outlined in the decree must be further refined so

the mechanism can be operational in time for the 2016-2017

winter period. This is the purpose of the rules, contracts and

agreements submitted by RTE on 9 April 2014, in accordance

with the responsibilities assigned to it in the decree, for approval

by the Minister and the opinion of the Energy Regulatory Com-

mission (Commission de régulation de l’énergie – CRE).

* * *

France will have to surmount major challenges to successfully man-

age its energy transition. Gone are the days when society could count

on abundant non-renewable sources: it must now find more efficient

and environmentally sound modes of production, transport and

consumption. This will require using less energy, optimising produc-

tion systems and making greater use of renewable energy sources.

As it stands, France boasts a competitive and low-carbon power

industry mainly because of energy choices made in the 1970s and

1980s (development of hydro- and nuclear power, increased use of

electricity through the promotion of electric heating, enhancement

of France’s energy independence). These choices helped make the

country more energy independent and competitive, and reduced

its carbon footprint, but they have also given rise to a particularly

intense peak demand phenomenon. In recent years, though growth

in average consumption (in energy terms) has slowed, peak power

demand has continued to trend sharply higher.

5

SUMMARY

The French capacity mechanism was designed to address this

issue by modifying consumption behaviour during peak peri-

ods (demand-based approach) while encouraging adequate

investment in generation and demand response capacities

(supply-based approach), at a time when energy markets’ abil-

ity to stimulate such investments was being questioned in

much of Europe.

Peak demand is not a problem in and of itself, if it is managed

in an economical and environmentally sound way without put-

ting security of supply at risk. And managing it efficiently is all the

more important since the decarbonisation policies implemented

to reach the climate targets set by the European Council in 2009

and adopted in the Commission's 2050 Energy Roadmap could

result in even greater use of electricity, for instance to power a

growing fleet of electric vehicles, meaning the peak demand phe-

nomenon could become permanent.

Against this backdrop, demand response can and must play

a central role. Though the capacity mechanism proposed is

technology-neutral and does not structurally favour any one

resource over another, it does make it possible to recognise the

capacities that actually serve security of supply needs, which load

curve management efforts clearly do. The specific procedures

proposed for demand response (flexible certification up until the

start of the delivery year, option to aggregate independently of

location or suppliers with which sites are affiliated) will facilitate its

integration. Generally speaking, the market design choices made

for France factor in demand response as a structural solution to

the capacity adequacy problem.

Introducing a capacity mechanism in France supports public

authorities’ objective of making the load curve more flexible, set

forth in Law 2013-415 of 15 April 2013 (“Brottes Act”). It is by no

means intended as an alternative to or substitute for the develop-

ment of demand response capacity: on the contrary, the capac-

ity obligation marks the final step in a four-year effort to open

all market mechanisms to demand response and allow it to par-

ticipate directly in energy markets. Over the coming months, RTE

will complete the process by removing the last technical barriers

to aggregation, consolidating France's position as the European

leader when it comes to leveraging demand response to the

extent permitted by the economic fundamentals of the sector.

A changing energy mix also is also creating greater need for flex-

ibility, notably on the demand side, due to the growing penetra-

tion of variable generation. The central risk factor for the French

power system could thus gradually evolve. Going forward, the

capacity mechanism will be able to shift from an exclusive

focus on national peak demand to an approach that ensures

adequate flexibility in a system characterised by increasing

intermittent energy penetration.

A new capacity mechanism cannot be implemented without

first carefully analysing the shortcomings of the existing market

model. In its Communication of 5 November 2013 on public

intervention in the electricity market, the European Commission

stressed that the first steps should be to analyse the causes of

generation inadequacy and to assess the impact of any measures

proposed.

Thanks in part to the introduction of coupling mechanisms that

help optimise and increase energy exchanges between countries

across Europe, the existing market model has definitely produced

results in terms of optimising electricity generation and flows

in the short term. That being said, market stakeholders, Mem-

ber States and academics are increasingly questioning whether

the model can ensure security of supply over the long term by

efficiently regulating investments in supply- and demand-side

capacity. Indeed, a theoretical analysis of how electricity markets

function highlights a certain number of shortcomings in the so-

called “energy-only” market when it comes to guaranteeing fair

remuneration of the capacities required to balance supply and

demand on the system during peak periods.

Security of supply is a public good. If it cannot be delivered – at

least over the medium term  – through the individual gratifica-

tion of private preferences, then the desired level of security of

supply must be defined by public authorities. In the absence of

a specific mechanism, there is no reason why the energy market

alone, even one that functions perfectly, would be able to achieve

the target level, as positive externalities would not be internalised.

Concerns about the functioning of electricity markets have a

special resonance in France due to the specific characteristics

of its power sector and notably the peak demand phenomenon

observed. The Poignant-Sido report of 2010 on peak demand

* * *

* * *

6

management notably underscored the electricity market's inabil-

ity, in its current form, to generate the right economic signals to

stimulate the investments necessary to guarantee that adequate

levels of supply- or demand-side capacity will be installed and

available during peak periods. And concerns have increased since

the report was published, as evidenced by the recent study on the

crisis in European electricity markets conducted by the General

Commission for Strategy and Economic Foresight for the Prime

Minister. Similar doubts have been raised elsewhere in Europe

and brought to the attention of the European Commission.

Two examples illustrate the challenges at hand.

The first relates to generation capacity. The steep investments

made in combined-cycled gas turbine plants in Europe between

2004 and 2012 created a paradox: A combination of slower

demand growth and the massive development of renewable

sources resulted in a temporary situation of excess capacity that

market stakeholders failed to anticipate. It could be corrected by

taking a large number of unprofitable assets offline, but this could

suddenly put security of supply at risk, and there might not be

enough power immediately available if weather conditions were

particularly unfavourable for variable generation. An adjustment

involving the closure of new and efficient facilities with low green-

house gas emissions would in theory go against the objectives

set forth in European guidelines.

The second relates to demand response. Though load modu-

lation efforts appear vital to the power systems of the future,

analyses show that they can only continue if their contribution

to security of supply is adequately remunerated. The capacity

mechanism does not by any means seek to lock in generation

capacity’s share in the mix, but instead supports policies that pro-

mote the development of demand response.

Addressing these issues requires carefully reviewing the archi-

tecture of the French electricity market while preserving the

benefits of European energy integration. The adoption of the

capacity mechanism will not result in less attention being paid

to the other structural changes under way, such as the integra-

tion of energy markets across all borders and time horizons, the

development of cross-border interconnections, the inclusion of

demand in all market mechanisms and the overhaul of renewable

energy support mechanisms. It will merely complement these

developments.

A number of European countries have already taken similar

approaches (Sweden, Finland, Ireland, Spain and Italy), are in the

process of doing so (United Kingdom, Belgium) or are considering

capacity mechanisms (Germany). These national mechanisms may

differ in their intent and form, but share common characteristics.

French Decree 2012-1405 of 14 December 2012 established

three fundamental principles to be applied in defining the

architecture of the capacity mechanism. It must (i) be a market

mechanism (market-based) based on volumes (quantity-based),

(ii) applying to all capacity (market-wide), and (iii) involving the

assignment of individual obligations that can be met by acquir-

ing certificates from a third party. Lawmakers thus opted for a

decentralised mechanism as opposed to a single buyer system.

These principles lay the groundwork for a mechanism adapted

to the specific characteristics of and issues faced by the French

market.

A market mechanism can achieve economic efficiency by allow-

ing obligated parties to engage in trading to minimise the cost of

their capacity obligation. A market-wide mechanism was chosen

to provide effective guarantees in terms of security of supply and

ensure that the effects of the mechanism are proportionate to

the objective pursued.

Conversely, a targeted mechanism such as a strategic reserve

would, in France's case, have to be regulated in such a way as

to address low-probability, high-impact events, such as one-in-

ten-year cold spells, since demand in France is highly tempera-

ture sensitive (a 1°C drop in the temperature during peak winter

periods generates 2,400 MW of additional demand). This type of

mechanism would end up removing a large portion of market

capacities (several GWs) and result in significant distortion.

In a word, the French capacity mechanism preserves the struc-

ture of accountability energy market stakeholders are accus-

tomed to and avoids having public authorities make decisions on

their behalf.

* * *

* * *

7

SUMMARY

These principles were applied in the decree in such a way as to

create a mechanism that allows market stakeholders to trade

capacity certificates so the security of supply target can be met

at the least possible cost.

Electricity suppliers' capacity obligations reflect the contribution of

their customers to the shortfall risk, notably their consumption during

the so-called “PP1” peak period and their temperature sensitivity.

Capacity certificates are issued to capacity operators based on

their contribution to reducing the shortfall risk. The certificates

reflect the availability of their capacities during the “PP2” peak

period and the technical characteristics of their capacities (for

instance energy constraints).

An effort was made to ensure that the mechanism would gen-

erate precise signals (obligation and certification levels should

accurately translate contributions to increasing and reducing the

shortfall risk) while also providing stability over time. Three deci-

sions reflect how this balance is achieved:

(i) Capacity is considered to contribute to reducing the shortfall

risk when its availability is effective and attested;

(ii) Commitments to make capacity available are proportionate to

the benefits for the system, meaning they are targeted to short

periods when demand is highest;

(iii) Fulfilment of participants' commitments and obligations is

verified based on measured data and observed availability. Due to

the specific characteristics of variable energy sources, their effec-

tive capacity levels can be calculated using an alternative system

based on a normative approach.

The mechanism proposed for France will thus allow consum-

ers and suppliers to manage the risk represented by capacity

obligations by leveraging their demand response potential

during peak periods. This means the capacity mechanism will

have a very different impact on highly temperature sensitive

consumers that absolutely cannot adjust their consumption and

consumers that can shed load during peak periods.

For the mechanism to be economically efficient, the capacity

certificate “product” must be clearly defined, related transactions

costs must be low, and it must be possible to trade certificates

under good conditions.

To this end, the framework governing the market's functioning was

defined in such a way as to facilitate trading and to give stakehold-

ers confidence in the capacity certificate product. The mechanism

parameters will be published four years before the delivery year

and stabilised over the duration of each term, meaning trading can

be carried out within a stable framework with players knowing that

the value of the product will not be modified because of interven-

tion from outside the market. RTE will keep a register to ensure that

capacity certificates can be traced and therefore that the product

is credible.

Various measures will give capacity market stakeholders all infor-

mation available about the security of supply outlook. Not only

can they consult the Adequacy Forecast Reports prepared by

RTE, but the data contained in two registers kept by RTE (certified

capacities and peak demand-side management registers) will

also be made public.

The final pillar required for the capacity certificate market to func-

tion properly is competition, and this is undoubtedly the aspect

that has generated the most concerns about the mechanism,

both in France and at the European level. Special attention was

paid to this issue. Through control and market monitoring proce-

dures, the regulator will be able to detect any abuse or manipula-

tion by market stakeholders and track all trades. This transpar-

ency measure is similar to the ones applied in the energy market,

notably at the European level with the REMIT and Transparency

regulations.

It should be noted that an analysis taking into account the decen-

tralised structure of the market and based on the net positions

of stakeholders gives a different picture of the real competi-

tive landscape. The fact that alternative suppliers benefit from

the capacity certificates associated with ARENH rights goes a

long way toward reducing market concentration by creating

* * *

8

upstream-downstream integration effects. The results will also

depend on the terms set by CRE and the Minister for transfers of

certificates associated with the ARENH mechanism.

In response to market stakeholders’ requests to have a compre-

hensive view of the mechanism's impact, RTE provided estimates

in September 2013 of the financial consequences for some cat-

egories of consumer. Its simulations are included and expanded

upon in the present report and used to present analyses of the

“first-round effects” of the implementation:

> The transfer to alternative suppliers of the capacity value asso-

ciated with ARENH rights will significantly reduce implemen-

tation costs for consumers. Costs will notably be very low for

electro-intensive users;

> Taking into account consumers' flexibility substantially modi-

fies the results: a consumer that sheds load during peak

periods can generate direct financial gains through the

mechanism;

> The real impact on consumers will depend on the rates sup-

pliers offer in a competitive environment: they will be able to

move away from regulated tariffs in setting rates for small con-

sumers, and will take into account any capacity they operate,

their commercial strategies, etc.

The points discussed in this report must be further developed.

It will now be possible to conduct more comprehensive stud-

ies, based on accurate models directly taking into account the

rules, to show the dynamic impact of the capacity mechanism on

investment and security of supply. These studies will be carried

out within the framework outlined in the decree and serve as a

basis for subsequent revisions of the mechanism.

The rules and functioning of the capacity mechanism must be evalu-

ated from a European perspective. In theory, security of supply falls

within the purview of EU Member States' energy policies, but there

is in practice significant interplay between Member States’ policies

in the integrated market. This is why the European Commission has

expressed reservations about the introduction of capacity mecha-

nisms in numerous Member States, underscoring the risk this poses

to the functioning of the internal market. The framework for analys-

ing public interventions to safeguard security of supply was recently

expanded to include the recommendations in the European Com-

mission’s Communication “Delivering the internal electricity market

and making the most of public intervention”.

An analysis of the French capacity mechanism based on the

European Commission’s guidelines shows that it complies with

EU law, meets the criteria of necessity and proportionality and is

compatible with recommendations on public intervention in the

area of security of supply.

There is nonetheless one outstanding issue relating to the inclu-

sion in the mechanism of cross-border capacity, which under the

terms of Decree 2012-1405 of 14 December 2012 is initially to

be taken into account implicitly, through a reduction of suppliers'

obligations. Both the European Commission and the Agency for

the Cooperation of Energy Regulators support the explicit inclu-

sion of cross-border capacity in capacity mechanisms, but recog-

nise the difficulties this will entail.

To comply with European expectations, RTE proposes in this report

a roadmap showing the steps to be taken to enable the explicit

participation of foreign capacity in the mechanism. This two-phase

approach is compatible with the recommendations of the European

Commission, which considers that implicit recognition of the con-

tribution of foreign capacity can be a temporary solution. RTE also

provides initial insight into how it will be possible to enable foreign

capacity to participate explicitly in the French capacity mechanism:

> Without harmonising security of supply criteria across Mem-

ber States, but rather upholding the division of competences

defined in the Treaty of Lisbon;

> Without reserving interconnector capacity;

> Within volume limits reflecting the physical limitations of import

capacity during peak periods;

> Subject to the creation of a mechanism for cross-border certi-

fication or control;

> Subject to the signature of agreements to govern operational

management in crisis situations.

These conditions imply significant regional coordination, so it

makes sense to start with an interim phase. One idea would

be to allow the explicit participation of foreign capacities in the

capacity mechanism subject to their inclusion in France's balanc-

ing mechanism. The length and scope of the phase could vary,

depending in part on the work conducted under the aegis of

Member States, and a principle of reciprocity could be applied.

Based on the roadmap proposed and the measures provided for

* * *

* * *

9

SUMMARY

The rules: Choices proportional to objectives will limit the cost to consumers

Peak periods under the mechanism

The days constituting peak periods are not determined ahead

of time but rather indicated one day ahead by RTE. For each

peak day, the time slots considered are from 7am to 3pm and

from 6pm to 8pm, or ten hours per day. The fact that RTE will

notify participants of peak periods a day ahead of time gives

them the visibility they requested during the consultation and

ensures that they have a real incentive to keep peak demand

in check, since their obligations are reduced accordingly. Peak

days will in all cases fall within the [January-March; November-

December] period.

The rules provide for targeted and short peak periods:

> For obligations, the PP1 period corresponds to a period of between

ten and 15 days, encouraging flexibility on the demand side;

> For certification, between 10 and 25 PP2 days will be notified.

This solution makes operators accountable for the availability of

their capacities at times when security of supply is truly at risk.

It also ensures consistency between contributions to reduc-

ing the shortfall risk and the number of certificates allocated,

including for capacities that are only available for short periods

such as peak generation and demand response capacities.

Time periods defined for the mechanism

Delivery year

The delivery year will correspond to a calendar year effective

the second year the mechanism is in place. This will notably

create consistency between the capacity mechanism and the

existing calendar of the energy market and fit better with con-

tractual practices in Europe to facilitate integration going forward.

In accordance with the terms of the decree, the first delivery year

will begin on 1 November 2016 and end on 31 December 2017,

with the months of July and August 2017 excluded.

The rules include specific provisions applicable to the first two

delivery years:

> Specific dates for the first delivery year (from 1 November 2016

to 31 December 2017, excluding July and August);

> A shorter gap between the start of the mechanism term and

the delivery year. The rules define the mechanism parameters

for these two years. Deadlines for certification requests have

been modified accordingly.

in the decree, RTE is prepared to launch a ten-month consulta-

tion to find a concrete solution for allowing the explicit participa-

tion of capacity situated outside France in the mechanism, in line

with the terms of the decree. The principles to be applied to the

consultation and related deadlines are set forth in the rules.

Transposing such a change into regulations would require

an amendment of the decree of December 2012. RTE is thus

requesting that the Energy Minister specify the mandate for this

next consultation phase when the draft rules are examined by the

administration and Energy Regulatory Commission.

* * *

10

Principles applied in calculating obligationsSuppliers' obligations are calculated based on the contribution of their

customers to the shortfall risk, which, in the current market environ-

ment in France, only applies to peak periods. Peak demand is thus rep-

resentative of the risk generated, such that a consumer that does

not consume power during peak periods has no capacity obligation.

Calculation of the obligation

Capacity obligations are calculated as follows:

> Parameters published by RTE: securityF and extremeT

> Data measured and/or calculated:

ConsumpSupplier, Pcertifieddemandresponseactivated, GradientSupplier, ActualT

Calculation of reference power by type of consumer

The calculation of reference power is segmented by type of con-

sumer: profiled, remotely metered, and reference power for the

supply of losses.

Each is calculated based on underlying consumption observed,

adjusting for the temperature sensitivity of obligated parties and

the load reduction for certified demand response capacity acti-

vated during PP1 hours.

Estimation of the gradient

To reflect the effective contribution of consumers to the shortfall

risk, gradients are established for each category of consumption

to prevent transfers between participants (from temperature-

sensitive to non-temperature-sensitive users, or from profiled to

remotely read users). RTE proposes that gradients for each obli-

gated party and type of consumer be used1, based on approxi-

mations that already exist and are not specific to the capacity

mechanism:

ObligationSupplier = securityF x [ ]ConsumpSupplier + Pcertifieddemandresponseactivated

+ GradientSupplier x (extremeT - ActualT)

> The gradient applied to non-temperature sensitive consum-

ers is nil. This category includes users connected to the pub-

lic transmission grid and public distribution grid with average

annual power exceeding 175kW;

> The gradient for profiled consumers corresponds to their

profile, with a measure introduced to stabilise the evolution

of the overall gradient from one year to the next: the over-

all gradient for profiled consumers is extrapolated in a linear

manner from previous years, and a scaling factor is applied to

bring the sum of the individual gradients back to this overall

gradient;

> The gradient for remotely metered consumers is calcu-

lated for each supplier based on the sum of all consump-

tion observed. This approach allows each supplier to be held

responsible individually for the real needs of its customers.

Obligation parameters

The parameters for calculating the obligation are determined

four years ahead of time. This allows obligated parties to estimate

the amount of their obligation and take any necessary demand

management actions based on their forecasts.

Security factor

The security factor reflects the margins required to cover residual

contingencies, notably on the demand side (excluding tempera-

ture sensitivity), as well as the contribution of interconnections

to security of supply. For the first delivery year, RTE proposes a

security factor of 0.93.

Extreme temperature

Since the capacity mechanism is designed to be a sort of “insur-

ance policy”, the obligation is calculated as if one-in-ten-year

cold conditions occurred every year. When the mechanism is first

implemented, the extreme temperature will be a series speci-

fied in the rules, with an average value of close to -2.6°C.

Principles applied to certification

Calculation of the capacity level

Generic certification principles

The certification method proposed in the rules involves:

> Certifying capacity based on data provided by capacity

operators;

> Measuring effective capacity levels based on controls during

the deliver year;

> Addressing, through settlements, differences observed

between certified and effective capacity levels.

For controllable capacities, effective capacity levels are esta-

blished based on information gathered during the delivery year

in question and verified after the fact.

* * *

11

SUMMARY

This structure will, by its nature, give operators incentives to

rebalance as quickly as possible, once they observe any discrep-

ancy between effective capacity levels and the levels they have

certified.

A degree of flexibility has been introduced to limit the cost

of rebalancing in the case of unforeseeable events affecting

capacities (generation or demand response). The procedure

applied in such instances (two zero-cost rebalancing “tickets”

issued to each capacity portfolio manager) is designed to pre-

serve incentives to submit the best availability estimates ahead

of time.

Verification of capacities

Capacity is certified based on self-declared data submitted by

operators, so certification must necessarily be backed by effi-

cient data collection and verification measures.

Operators of intermittent capacities can choose between the

generic framework applicable to all capacities and one that

neutralises the risks associated solely with the primary energy

source, applying in this case the contribution factor calcu-

lated for each type of generation. This factor reflects the cor-

relation between contingencies associated with variability and

shortfall risk situations, in such a way that the certified capacity

level reflects the technologies1 average contribution to reducing

the shortfall risk2. The availability of this option makes it possi-

ble for operators that want to hedge the variability of their capa-

cities (notably by associating them with flexible capacities  – for

instance storage or demand response) to reap the full benefits

of such hedging.

Certification procedures

Different certification procedures will apply to different types of

capacity:

> Existing generation capacities must request certification three

years before the start of the delivery year;

> Planned generation capacities that will be connected to the

grid can request certification once the first payment is made

under the connection agreement, up until two months before

the start of the delivery period;

> Demand response capacities can be certified up until two

months before the delivery period begins.

Setting the deadline for existing generation capac-

ities three years before the start of the delivery

year is crucial to give market stakeholders infor-

mation about the outlook for the system and for

the capacity market to generate economic signals

far enough ahead of time to allow enough capaci-

ties to be developed to meet the security of supply

criterion.

The fact that planned capacities can request cer-

tification closer to the start of the delivery period

makes it possible for all capacities to participate,

notably demand response and other capacities that

can be developed more quickly.

Capacity rebalancing

Rebalancing ensures consistency between the market and the

physical system up until the end of the delivery period. With

the rebalancing procedure proposed by RTE, an operator whose

capacity level is affected by a contingency can submit a rebalanc-

ing request:

> At no cost up until the start of the delivery period;

> The rebalancing cost will then increase gradually over the

course of the delivery period, based on the number of PP2 day

notifications, to incentivise operators to submit their best esti-

mates of the expected performance of their capacities.

The principle applied is that all certified capacity must be acti-

vated at least once a year. For verification to be efficient and pro-

portional, it must whenever possible be an extension of existing

measures, notably the balancing mechanism. Barriers to integra-

tion must be reduced: To this end, flexible aggregation rules will

be applied as soon as the mechanism is in place to allow for the

creation of certification entities, with coherent verification meas-

ures applied at the same level of aggregation, notably for demand

response capacity.

In more specific terms:

> Under the generic verification system, controls focus on quanti-

ties injected for generation capacities and actual activation for

demand response capacities, relying on the procedures for veri-

fying the activation of demand response capacities and on injec-

tion data for each capacity;

1 Concretely, the sum of the gradients of profiled consumers must correspond to the temperature sensitivity of profiled users taken as a whole, no more and no less. This segmentation makes it possible to envisage different approaches for each category of consumption. 2 The value of this factor will depend (i) on the capacity considered, (ii) on the volume of variable capacity already in the system, and, more generally, (iii) on the power system in which the capacity is considered.

* * *

12

> The audit-based verification procedure is used to confirm that

data declared by operators and gathered reflect the real perfor-

mance of the capacities;

> The activation test-based verification procedure complements

market-based activation and is designed to guarantee that all

capacities have been activated at least once. The idea is to con-

duct random tests for each capacity, with no prior notice to the

operator. Capacities cannot be tested more than three times

per delivery period.

Principles of the imbalance settlement

Unit price of the settlement

To limit arbitrage possibilities and generate the right incentives,

the settlements of obligated parties and capacity portfolio

managers are calculated using the same unit price.

RTE is proposing a two-part settlement system:

> When security of supply is not at risk, the settlement price will

be based exclusively on the market price. An incentive coef-

ficient will still be necessary to ensure that stakeholders have

incentives to operate through the market rather than wait for

a settlement;

> When security of supply is at risk, the imbalance settlement will

be based on an administered price. This price, which by defi-

nition defines the maximum value capacity can reach on the

market, plays a central role in encouraging investment in new

capacities. It is set based on the annualised cost of reference

peak capacity and published four years before the delivery year

by the Energy Regulatory Commission.

Indicator used to determine whether security

of supply is at risk

At the end of the peak period, RTE calculates the overall imbal-

ance observed, which corresponds to the algebraic difference

between total effective capacity and total effective obligations.

This overall imbalance reflects the physical tension between

effective obligation and capacity levels. The market is thus

informed of any uncertainty arising on either side and capacity

adjustment measures can be taken. Calculating the overall imbal-

ance also prevents a form of market manipulation wherein opera-

tors could certify too much (or too little) capacity to influence the

market price.

It is also necessary to define a threshold value for the overall

imbalance, above which security of supply is considered to be at

risk. This value corresponds to the so-called imbalance limit.

An imbalance limit of 2 GW ensures that a switch from the mar-

ket price to the administered price will only occur when secu-

rity of supply is at risk, and will not be based on the occurrence

of short-term risks.

Inclusion of cross-border capacity

The rules call for the contribution of interconnections to be

accounted for as a whole. The security factor takes into account

projected contributions during peak periods, reducing the obliga-

tion of each supplier accordingly.

To leave time to discuss the roadmap presented in this report and

propose concrete solutions for the explicit participation of cross-

border capacity, the rules stipulate that RTE will submit a report

on the explicit inclusion of cross-border capacity ten months

after the rules are published, potentially proposing at that time

changes to the regulatory framework. This provision complies

with the decree, article  20 of which calls for the system allow-

ing the participation of cross-border capacity to evolve based on

reports prepared by RTE and CRE. This consultation will be con-

ducted under the terms of a mandate issued by the Minister.

Analysis of the dynamic impact of the mechanism

The rules call for RTE to conduct studies on the dynamic impact

of the mechanism, in accordance with the principles set forth in

this report. The results of these studies will be included in a report

on how France's interconnection with other European markets is

to be taken into account going forward, and on ways to improve

the functioning of the capacity mechanism. RTE will submit the

results of its work to CRE and the Minister, and also share them

with market stakeholders.

13

SUMMARY

FOREWORD

French law 2010-1488 of 7 December 2010 reforming the

organisation of the electricity market calls for the creation

of a capacity mechanism in France. Decree 2012-1405 of 14

December 2012 stipulates that RTE is to propose rules for the

capacity mechanism, specifying exactly how it will function.

This was the subject of RTE's submission to the Energy Regula-

tory Commission and Energy Minister on 9 April 2014.

Originally referred to in the Poignant-Sido report of 2010, the

capacity mechanism is intended as a solution to the particu-

larly pronounced peak demand phenomenon observed in the

French power system. It is seen as a way to modify consump-

tion behaviours during peak periods (demand-based approach)

while also encouraging adequate investment in generation

and demand-side capacities (supply-based approach).

It is being designed during a period of energy transition in

France, a process that underscores the need for tools that

can allow new public policies to be implemented efficiently

so targets can be met at the lowest possible cost. The capac-

ity mechanism can act as a communication channel between

policy objectives and the market and allow the power system

to adapt to keep up with adequacy needs.

The present report accompanies the draft capacity mecha-

nism rules RTE submitted to the Energy Minister and Energy

Regulatory Commission, following the consultation organised

in 2013. It introduces proposals made by RTE and situates

them within the context of previous discussions on security of

supply and capacity mechanisms.

This report is divided into ten chapters. Chapter 1 outlines the

justifications for the implementation of a mechanism focusing

on security of supply, based on an analysis of the theoretical

economic framework and observation of the actual function-

ing of energy markets. Chapter 2 describes how key choices

were made about the capacity mechanism design, while chap-

ter 3 discusses the provisions set forth in Decree 2012-1405

and the main decisions made in the capacity mechanism

rules to ensure that the mechanism effectively contributes

to security of supply. Chapters 4 through 6 describe the fun-

damentals of the proposed mechanism including the main

procedures for calculating capacity obligations, capacity certi-

fications and settlements. The procedures proposed to ensure

that the capacity market is transparent and that competition

within it will be free and undistorted are presented in chapter

7. Chapter 8 includes an assessment of the impact the capac-

ity mechanism will have on different categories of consumer.

In chapter 9, readers will find an overview of the discussions

held at the European level about the participation of foreign

capacity in capacity mechanisms and a presentation of the

options selected in the rules, along with an outline of possi-

ble modifications. Chapter 10 provides data supporting the

French capacity mechanism's compatibility with the provisions

of European law.

14

1. WHYACAPACITYMECHANISMIS NECESSARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

1.1 Theoretical evidence of imperfections in energy markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

1.1.1 Optimal functioning of energy markets within the theoretical framework of the “energy-only” market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 181.1.2 Questioning the energy-only market’s ability to guarantee the optimal level of investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 201.1.3 Failures of the energy-only market in the presence of externalities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 221.1.4 Imperfections of the energy market in terms of managing investment dynamics. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

1.2 Concrete consequences of energy market imperfections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

1.2.1 Assessment of security of supply risks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 251.2.2 Impact on capacity remuneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 281.2.3 Existence of investment cycles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

1.3 Projected trends in demand over the coming years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

1.3.1 The growing role played by electricity in achieving energy policy objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 321.3.2 Growing need for flexibility in European power systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

1.4 Efforts to reform market structures in France . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

1.4.1 Ongoing integration of energy markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 341.4.2 Participation of demand response in energy markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 361.4.3 Reform of renewable support mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 371.4.4 Implementation of the capacity mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

1.5 Capacity mechanisms in Europe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

1.6 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

2. CHOOSINGTHERIGHTCAPACITYMECHANISMFORFRANCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

2.1 Why a quantity-based market mechanism .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

2.2 Why a market-wide capacity mechanism .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

2.2.1 Provide guarantees in terms of security of supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 462.2.2 Address market imperfections and avoid distortion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 472.2.3 Minimise the cost to consumers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 512.2.4 Economic efficiency in the presence of investment cycles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 532.2.5 Suitability to France’s situation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

2.3 Why a decentralised capacity mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

2.3.1 Compatibility with the philosophy of the European energy market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 562.3.2 Ability to address France’s specific challenges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 572.3.3 Timescales of the decentralised market and economic efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

2.4 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

3. GUIDELINESFORTHECAPACITYMECHANISMRULES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

3.1 Architectural principles set forth in laws and regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

3.1.1 Drafting of the capacity mechanism decree . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 623.1.2 Provisions laid down in the decree . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 643.1.3 Regulatory framework provided for in the decree . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

3.2 Purpose of the capacity mechanism rules: Guarantee real contributions to security of supply . . . . . . . . . . . . . . . . 69

3.2.1 Nature of commitments by capacity operators (installed or available capacity) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 693.2.2 Duration of capacity commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 703.2.3 Methods for calculating the obligation and certifying capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 713.2.4 Reference data used to calculate obligations and certifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 723.2.5 Methods of valuing demand response . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73

3.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

SUMMARY

15

SOMMAIRE

4. CAPACITY OBLIGATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76

4.1 General provisions regarding the obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76

4.1.1 Obligated parties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 764.1.2 Reference power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 764.1.3 Security factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 794.1.4 Summary of obligation principles. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

4.2 Period for measuring suppliers’ obligation: The PP1 peak period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81

4.2.1 Definition of PP1 and contribution to the shortfall risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 824.2.2 Definition of PP1 and peak demand management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 834.2.3 Notification of PP1 hours . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 844.2.4 Sensitivity of the obligation to the location in time of PP1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 874.2.5 Provisions adopted in the rules on PP1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90

4.3 Delivery year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .90

4.3.1 Overlapping year centred on a winter or calendar year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 904.3.2 Impact of the choice of the delivery year on the functioning of the mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 914.3.3 Sensitivity of the capacity mechanism to the definition of the delivery year with regard to the security of supply objective . . . . . . . . 914.3.4 Sensitivity of suppliers’ obligation to the choice of delivery year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91

4.4 Parameters of the capacity obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

4.4.1 Determination of the obligation parameters (extreme temperature and security factor) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 944.4.2 Extreme temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 964.4.3 Security factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98

4.5 Determination of the obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

4.5.1 Perimeter of an obligated party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1004.5.2 Observed consumption. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1014.5.3 Sensitivity of consumption to temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1024.5.4 Taking into account certified demand response measures activated . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1144.5.5 Specific provisions for the compensation of losses on public transmission and distribution systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117

4.6 Timetable for suppliers’ obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117

4.6.1 Before the delivery year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1174.6.2 During the delivery year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1174.6.3 After the delivery year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118

5. CAPACITYCERTIFICATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120

5.1  General provisions governing the certification of capacities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120

5.1.1 Players involved in capacity certification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1205.1.2 Capacity level. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1215.1.3 PP2 peak period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1265.1.4 Calculation of the capacity level . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126

5.2  Period covered by capacity certification (PP2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129

5.2.1 Period during which the contribution in estimated . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1295.2.2 Consequences of the PP2 period defined on the distribution of certificates between technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1315.2.3 Consequences of the PP2 period defined on the variability of certificate volumes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1325.2.4 Approach adopted in the rules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1335.2.5 Notification of PP2 hours . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1335.2.6 Sensitivity of effective capacity level to the location in time of PP2 hours . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1345.2.7 Provisions adopted in the rules on PP2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 136

5.3 Calculation of the capacity level . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137

5.3.1 Available power of capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137

5.3.2 Determination of the coefficient to reflect the technical constraints of capacity (K) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137

16

5.4  Certification requests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139

5.4.1 Definition of capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1395.4.2 Certification deadlines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1415.4.3 Withdrawals of capacities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1435.4.4 Certification fees. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 144

5.5 Rebalancing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 144

5.5.1 The rebalancing process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1445.5.2 Financial consequences of rebalancing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145

5.6 Collection of data required to calculate effective capacity level . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147

5.6.1 Linking of certification entities with BM and NEBEF entities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1485.6.2 Collection of activated power data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1485.6.3 Collection of activatable power data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1495.6.4 Collection of maximum energy data for PP2 days . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1495.6.5 Collection of weekly maximum energy data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149

5.7  Capacity verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149

5.7.1 Initial consistency check at the time of certification. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1505.7.2 Verification of certified intermittent capacities under the normative approach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1505.7.3 Verification of certified capacity under the generic approach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 150

6. THE CAPACITY MECHANISM SETTLEMENT SYSTEM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152

6.1 General principles of settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152

6.1.1 Capacity rebalancing by suppliers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1526.1.2 Imbalance settlement at the capacity portfolio manager level . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1536.1.3 Overview of principles governing settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153

6.2 Key aspects of capacity mechanism settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154

6.2.1 Security of supply target . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1546.2.2 Unit price of the settlement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1546.2.3 Interplay between capacity rebalancing by suppliers and imbalance settlement at the capacity portfolio manager level . . . . . . . . . . . 154

6.3 Settlements provided for in the rules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154

6.3.1 Interplay between capacity rebalancing by suppliers and the imbalance settlement at the capacity portfolio manager level . . . . 1546.3.2 Unit price for the settlement and the security of supply target . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1556.3.3 Definition of indicators for assessing threats to security of supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 156

6.4 Assessment of the impact of the provisions on settlements for market stakeholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 158

6.4.1 Framework for the assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1586.4.2 Principle of the study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1586.4.3 Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 159

7. MARKETFUNCTIONING:TRADING,TRANSPARENCYANDCOMPETITION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 162

7.1  Trading of capacity certificates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 163

7.1.1 Publication of mechanism parameters at the start of the term . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1637.1.2 Nature of the product and organisation of trading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1637.1.3 Trading procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 164

7.2 Transparency of the mechanism .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 165

7.2.1 Publications relating to the registers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1657.2.2 Publications relating to the capacity obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1677.2.3 Publications relating to the functioning of the capacity market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 168

7.3 Competition in a decentralised capacity market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 169

7.3.1 Competition and market power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1697.3.2 Competition under the capacity mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1707.3.3 Monitoring of the market’s functioning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 174

7.4 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 176

17

8. CAPACITY MECHANISM IMPACT ASSESSMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 178

8.1 Challenges associated with detailed modelling of how capacity mechanisms function . . . . . . . . . . . . . . . . . . . . . . . . . . . . 178

8.1.1 Analysis of technical parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 178 8.1.2 Assessment of the aggregate effects of the mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 179

8.2 Limitations of existing analyses of how the capacity mechanism functions in an interconnected market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 180

8.2.1 Analysis of the report accompanying the European Commission guidelines on public interventions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1808.2.2 Factors minimising the French mechanism’s impact on neighbouring countries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 183

8.3 Detailed analysis of short-term effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 184

8.3.1 Hypotheses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1858.3.2 Quantitative assessment of cost to consumers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 189 8.3.3 Impact on the CSPE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 195

8.4 Plans to strengthen the impact assessment system .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 196

8.4.1 A mechanism simulator made available to stakeholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 196 8.4.2 Expand the “first-round” impact assessment by factoring in small consumers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 197 8.4.3 Include a study on the dynamic impact of the mechanism over the long term in the assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 197

9. EUROPEANINTEGRATIONOFTHE FRENCHCAPACITYMARKET . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 198

9.1 Interconnections’ contribution to security of supply in France . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 198

9.1.1 Integrating power systems improves security of supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1989.1.2 Recognition of the cross-border dimension in the French capacity market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 199

9.2 Current status of cross-border participation in capacity mechanisms .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200

9.2.1 Cross-border participation in existing and planned capacity mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2009.2.2 Decision to implicitly recognise foreign capacity in the French capacity mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 201 9.2.3 Towards an explicit cross-border participation in capacity mechanisms in Europe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 202

9.3 A practical way forward for explicit cross-border participation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .205

9.3.1 Key principles to design a solution for explicit cross-border participation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2079.3.2 Relevant event to be considered to allow effective cross-border exchanges of capacity products . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2089.3.3 “No-go” solutions to implement explicit cross-border participation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2099.3.4 Target solution for explicit cross-border participation in the French capacity market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2109.3.5 Shaping a transitory solution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 211

10.COMPLIANCEWITHEUROPEANPROVISIONSANDPRINCIPLES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 212

10.1 The European legal framework governing State intervention to ensure security of supply . . . . . . . . . . . . . . . . . . . 212

10.1.1 Competence of Member States with regard to security of supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21210.1.2 Regulation of Member States’ competence through the provisions of the Treaty and secondary legislation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21310.1.3 Legal forms of public intervention . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 215

10.2 Compliance with the principles of necessity and proportionality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 216

10.2.1 Principle of necessity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21610.2.2 Principle of proportionality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 226

10.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .229

BIBLIOGRAPHY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 232

ANNEXE1:LISTOFPARTICIPANTSINMACCONSULTATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 234

ANNEXE2:CONTRIBUTIONSTOTHESTAKEHOLDERCONSULTATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 236

SOMMAIRE

18

1.1.1 Optimal functioning of energy markets within the theoretical framework of the “energy-only” market

The European power market is being created by integrating

markets and networks. Since deregulation began with the first

electricity directive of 1996, individual Member States have

been organising their industry around common principles (libe-

ralised system more than the vertical integration of existing

markets) and including electricity in the free trade of goods

to encourage intra-European exchanges. Electricity prices are

determined by supply and demand in a competitive market and

will thus in theory optimise exchanges between countries and

allow consumers to choose the generators and suppliers that

have the most competitive prices.

Detailed regulations govern the functioning of the

market, applying to all exchanges and relationships

1. WHY A CAPACITY MECHANISM IS NECESSARYElectricity markets are undergoing major changes in many

European countries, including France. Market opening may have

helped optimise electricity flows in the short term, but there

are growing concerns about the ability of mechanisms imple-

mented in the early 2000s to efficiently regulate investments

in generation and demand response capacities and safeguard

security of supply over the long term.

Having a capacity mechanism in place will profoundly change

the architecture of the electricity market by correcting the

shortcomings observed with the current system. The goals are

to encourage investment in capacities that can be available

during peak demand periods and, in a broader sense, to lay the

foundations for the energy transition by rewarding investments

that are useful to the power system in proportion to their bene-

fits to the community.

RTE’s draft rules are part of a more comprehensive assessment

of the organisation of the deregulated power system. This chap-

ter outlines the justification for public intervention. It begins with

a description of why the market’s theoretical ability to safeguard

security of supply over the long term is increasingly being called

into question (§ 1.1). Next, it explains that an observation of the

market’s functioning tends to support these doubts, and sug-

gests that closer monitoring of security of supply will be required

from 2016-2017 taking into account the specific characteristics

of France’s current power system, i.e. its temperature sensitivity

and the occurrence of periods of peak demand (§ 1.2). This ana-

lysis is followed by a presentation of the public policies currently

being implemented in France and the European Union, and

shows how the specific issues facing France could become even

more pressing with the addition of a “flexibility” component

(§ 1.3). The chapter also outlines the programme for overhauling

the functioning of markets, of which the capacity obligation will

be one aspect (strengthening of cross-border interconnections,

operations in the day-ahead, intraday and real-time markets),

and discusses the reforms being made to renewable support

mechanisms (§  1.4). The last section illustrates how the intro-

duction of a capacity mechanism in France will be in keeping

with a broader trend in Europe (§ 1.5).

1[European Council, 2011]

1.1 Theoretical evidence of imperfections in energy markets

between stakeholders and institutions: in other words, the Euro-

pean power market is a result of public intervention. These regu-

lations are constantly being better coordinated between Mem-

ber States. Electricity markets in Europe thus operate based on

standard market designs and are committed to gradually har-

monising structures until a “target model” is achieved:

Safe, secure, sustainable and affordable energy contributing

to European competitiveness remains a priority for Europe.

Action at the EU level can and must bring added value to that

objective… […]The EU needs a fully functioning, interconnec-

ted and integrated internal energy market1.

The European Union needs an internal energy market that is

competitive, integrated and fluid, providing a solid backbone

for electricity and gas flowing where it is needed. To tackle

Europe’s energy and climate challenges and to ensure

19

WHY A CAPACITY MECHANISM IS NECESSARY / 1

affordable and secure energy supplies to households and

businesses, the EU must ensure that the internal European

energy market is able to operate efficiently and flexibly2.

What are currently being harmonised are mechanisms for remu-

nerating energy generated (MWh) over different timeframes

(annual, day-ahead, intraday) and in different regions (recogni-

tion of interconnections). These mechanisms are considered

the cornerstone of the European energy market, though Mem-

ber States have their own specific instruments in place as well,

for instance in the area of reserves set aside by transmission

system operators to operate the power system3.

Most provisions in the framework governing the construction of

the European power market apply to energy trading between

firms in a competitive market, and correspond to the theoretical

model of the energy-only market. In an energy-only market, all

generation capacity dispatched is remunerated at the marginal

production cost of the mix. Free and undistorted competition

guarantees that generators’ prices reflect their real costs. The

energy price is the only economic signal needed: it ensures

the optimal use of generation assets in the short term (since all

capacities compete, only the most competitive are used to meet

demand), and also drives long-term investment (the prospects

for capacities to generate profits in the market lead rational

players to invest in the most competitive technologies and retire

units that are no longer profitable, meaning the mix adjusts to

demand in an optimal way):

The electricity market has two coordination functions. First,

in the short term, it ensures the efficient operation of com-

petitors’ equipment. Second, it indicates scarcity of capacity

in different technologies via a price signal to orient investors’

long-term decisions4.

In practice, the regulatory framework of the European energy

sector is designed to create the right conditions for an energy-

only market to function. Where day-ahead and intraday mar-

kets are concerned, the harmonisation of exchanges is based

on shared standards for products and timeframes structured

around power exchanges and system operators, with market

coupling allowing for ever greater integration of processes at

the European level. Financial products developed based on

these underlyings allow participants to manage price risks over

the long term and base their investment decisions on their own

forecasts and those of the market as a whole. The general sys-

tem governing the market’s functioning can be described as

follows:

Most energy markets in Europe only remune-

rate energy generated, since there is no specific

mechanism for assigning a value to capacities

that can be used to generate power when sup-

ply is tight (exceptions are Spain, Portugal, Italy,

Greece and Ireland, which apply a form of capa-

city remuneration). The underlying principle

is that electricity prices will increase if market

stakeholders see an imminent capacity shor-

tage, resulting in additional investment5.

The main characteristic of the energy-only model

is that it describes a balanced situation in which

a short-term approach to market functioning is

compatible with the long-term financing needs

of each power plant. In particular, generators’ pro-

fits exactly cover their fixed costs for each type of

generation capacity (base, semi-base and peak).

Indeed, in the energy-only model, each power

plant generates profits on the market when the

energy price is higher than its variable cost: the

difference between this price and the variable

cost is called the inframarginal rent6. Equilibrium

is achieved since market stakeholders base invest-

ment decisions on rents generated in the market:

generation capacity is invested in or retired in res-

ponse to this economic signal.

In this theoretical model, the market price climbs

above the variable cost of peak generation capa-

city7 only when supply is extremely tight, in other

words during periods of load curtailment8. In this

case, the inframarginal rent represents the diffe-

rence between the marginal production cost of

the mix (i.e. the variable costs of the most expen-

sive plant to run) and the energy price in load cur-

tailment situations. This price will in theory cor-

respond to consumers’ willingness to pay to avoid

service interruption9, or their marginal propensity

to pay, which is referred to as the cost of unserved

energy (or VoLL, Value of Lost Load).

The figure below illustrates the merit order of generation capa-

city and the price duration curve for peak load hours in a situa-

tion where long-term equilibrium is achieved10. The inframar-

ginal rent generated annually by peak generation plants (blue

area) perfectly covers their annualised fixed costs, along with a

portion of those of other capacities.

2[EC, 2012a]

3Consistent with the reserve requirements and levels defined in the Load Frequency Control and Reserves Network Code being adopted for Europe.

4[Finon, 2013]

5[General Commission for Strategy and Foresight, (CGSP),2014] Capacity mechanisms also exist in many other European countries, as discussed in section 1.5 of this report. Electricity markets in Europe are nonetheless still organised primarily around the energy market.

6 When the market price is higher than the marginal cost of the most expensive plant to run, the inframarginal rent is considered a scarcity rent.

7Peak load plants are dispatched last.

8Load shedding involves rationing supply to some consumers to restore/maintain the supply-demand balance.

9For the market to function perfectly, the price must accurately reflect consumers' marginal willingness to pay for electricity, which is not technically feasible in practice. What is given here is an approximation of a single value of the cost of unserved energy.

10The price duration curve is the curve obtained by arranging in decreasing order prices per MWh of electricity observed over all hours of a year.

20

If the energy price does indeed reach the cost of unserved

energy during periods when load curtailment is required, the

corresponding inframarginal rent will send a signal to the market

about the optimal level of investment for society. This optimal

level represents a perfect trade-off between the collective cost

of load curtailment for society and the cost of investing in new

capacities.

The key result of the energy-only model  – that dimensioning

is optimised over the long term  – is based on very signifi cant

assumptions, among others that the market will function per-

fectly even in shortage situations, when available capacity

cannot fully meet demand. During such periods, the energy

price should be able to rise to a very high level  – that of the

cost of unserved energy  – which some countries and market

Figure 1 – Illustration of the merit order and price duration curve for peak load hours in a perfect energy-only market

Base VC

VoLL

Peak VC

Semi-base VCPrice duration curve

8760

Peak capacity

Peak VC

VoLL

Peak VC

VoLL

Annual peak operation time

Load shedding

Optimal load shedding

Quantity (GW)

Quantity (GW)

Price (€/MWh)

Price (€/MWh)

Hours of operation

Price (€/MWh)

Price (€/MWh)

Hours of operation

stakeholders estimate at several tens of thousands of euros per

MWh. This central assumption seems fairly unrealistic, limiting

the scope and meaningfulness of the result.

1.1.2 Questioning the energy-only market’s ability to guarantee the optimal level of investment

1.1.2.1 Introducing a more realistic model of the energy

market

A number of academic studies analyse the dynamics of invest-

ments in power generation capacity in new energy markets.

Many of these studies focus on the failures of existing markets

and possible ways to fi x them.

21

WHY A CAPACITY MECHANISM IS NECESSARY / 1

The first limitation identified with the energy-only model has to

do with the assumption that markets can manage shortage situa-

tions in an optimal manner. What is being challenged, in more

specific terms, is (i) how the value of lost load is defined during

shortage situations, and (ii) whether prices are allowed to rise

to the value of lost load. In the model presented in the previous

section, the failure of prices to reach the value of lost load during

peak periods creates a deficit for economic agents who will not be

able to cover their fixed costs, at least in the short term.

In economic literature, the term missing money is used to des-

cribe this difference between fixed costs and the inframarginal

rent (see box below). Various factors can cause this phenome-

non to occur.

First, regulations or practices may limit the inframarginal rents

of electricity providers during shortage periods. This is notably

the case when electricity prices are capped, a situation that has

been covered in detail in economic literature due to the wides-

pread use of caps in electricity markets in the United States in

the 2000s, after the California crisis11. But similar effects can

occur even when no price cap is applied, if particularly high

prices are considered unacceptable. For instance, regulators are

in charge of protecting consumers from excessive price spikes

since electricity is an essential good. Public authorities’ reac-

tions to very high prices create an “implicit cap” above which

prices cannot rise.

The actual functioning of power systems is also

more complex than what the model presented

above assumes. If system operators reserve capa-

city ahead of time for the system, energy prices

can decline during peak periods. Indeed, some of

the capacity dispatched in these situations is remu-

nerated in advance, when it is reserved, and that

revenue is not reflected in the marginal prices offe-

red on markets or capacity mechanisms. This sim-

ply shows that no power system functions exactly

according to the principles of the energy-only mar-

ket. The academic literature also notes that in other

contexts, operational measures system operators

may take to limit the impact of load curtailment

can obstruct price spikes12. Lastly, it is technically

impossible today to distribute shortages based on

consumers’ willingness to pay. Security of supply

can thus be analysed within the framework of the

theory of public goods (see § 1.1.3).

The second limitation identified with the energy-

only model relates to the overly simple assumptions

adopted. Oversimplifications of the real situation

(e.g. convexity of costs13, optimality of the price set-

ting method14 or the failure to take into account the

discretionary nature of investments15) necessarily

limit the meaningfulness of the results.

11It should be noted that the rules governing the functioning of electricity markets in Europe also regulate price formation through a price floor/cap system (for instance: –€500/MWh – €3,000/MWh within the NWE region).

12See for example [Joskow, 2007]. This consideration seems to apply mainly to the context in the United States. In France, such measures would only be taken once markets had had the opportunity to function.

13It is assumed in the model that each time step is associated with an independent merit order; the model thus does not take into account the dynamic constraints associated with generation or demand response capacities.

14[Batlle, 2012]

15Most capacities have standard output, which restricts investment decisions.

16Ill-adapted generation mixes and even market imperfections can also translate into extra money for some capacities.

17For this reason, RTE opted not to focus its analyses on the missing money issue during the 2011 consultation on the capacity mechanism.

The missing money concept

The term “missing money” usually refers to a situation where capacity is insufficiently remunerated due to market

imperfections. When there is missing money, it implies that capacity would legitimately earn more revenue if the mar-

ket was functioning perfectly.

However, even in a market that operates perfectly, it is possible, and sometimes legitimate, for capacity remuneration

not to cover long-term costs. Indeed, once capacity exceeds the optimal level (surplus capacity), the energy market

acts as a stabilising feedback loop by undercompensating energy supply.

Symmetrically, situations of under-capacity can lead to capacity earning more revenue than it would at equilibrium,

resulting in additional revenue that is referred to as “extra money”16. It is normal for market stakeholders to be “subjec-

ted” to such revenue swings insofar as they had sufficient visibility when making their investment decisions.

The term missing money must therefore be used with caution. Missing money caused by market imperfections is

indeed undesirable, but when capacity remuneration is lower because there is too much capacity, then the market

is merely self-regulating, as it is expected to do. In other words, even if it is proven that capacity is earning insufficient

remuneration, corrective measures are not necessarily justified17.

Hereinafter, the term missing money is used only to refer to situations where capacity earns insufficient revenue due

to market imperfections.

22

When more realistic assumptions about actors’ behaviours

are applied (asymmetry of information, copycatting, etc.), the

conclusions about the energy-only market’s ability to regulate

investments efficiently are not the same. Taking the high varia-

bility of revenues in the energy-only market on the one hand

together with market stakeholders’ risk aversion and the limited

financial tools available for hedging risks on the other, it seems

that the price signals generated by the energy-only market can-

not efficiently drive investment.

These considerations lead to two conclusions, which are pres-

ented and discussed in sections 1.1.3 and 1.1.4, respectively:

> Security of supply is a public good that will not be sponta-

neously delivered through the energy-only market model;

> Energy-only markets are subject to specific investment cycles

that jeopardise the achievement of a stable equilibrium.

1.1.3 Failures of the energy-only market in the presence of externalities

1.1.3.1 Consequences of market failures for

investment

A true representation of energy markets shows that it would

be fairly unrealistic to assume that shortage situations will be

managed perfectly by the market. This creates doubts about

whether prices could rise to the levels required for fixed costs to

be exactly covered.

Nor would the impact be limited to peak capacities if a reve-

nue shortfall occurred during peak periods. All units operating

during these periods would be affected, including base-load and

semi base-load capacities, though the consequences would be

proportionately greater for peak power plants. In this case the

missing money problem could remove incentives to invest in

any type of capacity.

In concrete terms, it is doubtful that market stakeholders sub-

ject to economic performance requirements will agree to keep

unprofitable assets in operation indefinitely. If they observe a

revenue deficit on generation assets remunerated at the mar-

ginal price, stakeholders are likely to adjust their investment or

selling strategies to integrate this risk:

> By decommissioning assets or underinvesting:

when supply is reduced, inframarginal rents

are restored to levels that allow fixed costs to

be covered, which, in the model presented

above, translates into more frequent shortage

situations;

18[Léautier, 2012] “A wholesale price cap simplifies the analysis, while preserving the main economic insights.”

> By adding a margin to their selling prices, above and beyond

the variable cost of operating the assets.

In the first case, the profitability of generation assets is restored

at the expense of security of supply; in the second, the optimal

structure of the mix is modified. In both cases, consumers end

up paying for a market failure, and the structure of the gene-

ration mix moves away from the theoretical ideal.

Figure 2 below illustrates trends in the extremity of the merit

order and price duration curve for peak load hours when the

missing money issue is not addressed, resulting in a decrease

in capacity offered. The limitation of profits is illustrated by the

existence of a price cap: this is a simple and general represen-

tation of what happens when there is missing money18. The

situation is then compared to the theoretical framework of the

perfect energy-only market. In this situation, inframarginal rents

are restored for all capacities dispatched thanks to an increase

in the frequency of load curtailment.

1.1.3.2 Analysis from the standpoint of public goods

theory

In theory, a perfect energy-only market will create a level of

security of supply that corresponds to the value of lost load. This

value will vary depending on consumers, who are not all equally

sensitive to service interruption.

As discussed above, the idea that the market value of unserved

energy represents the real value of that energy is a very strong

assumption. There are in fact many technical and practical fac-

tors that prevent the market from fairly valuing unserved energy.

An instantaneous participation of demand in energy markets

during shortage situations is notably required for the market

value of unserved energy to be revealed. Efforts made in France

over the last three years to strengthen the regulatory framework

governing demand response, and the creation of a framework

for its participation in energy markets (NEBEF), are big steps in

the right direction (see § 1.4 and chapter 10). However, the mar-

ket’s handling of shortage situations can only be analysed from

a very long-term perspective.

Security of supply is thus a public good: when it is guaranteed,

everyone benefits, but when this is not the case all network

users are affected, regardless of the value they place on it.

The availability of peak capacities creates positive exter-

nalities for security of supply with no financial benefits for

operators of these capacities. This reduces investment

incentives: it is not in the interest of market stakeholders

23

WHYACAPACITYMECHANISMISNECESSARY / 1

to invest in certain capacities that would benefit security of

supply if the profit they generate is lower than the benefit

for society.

In economic theory, this justifi es public authorities regulating

the market’s operation by defi ning a collective preference  –

since individual preferences regarding security of supply will not

emerge – and ensuring that the target is met through a mecha-

nism that aligns individual incentives and investments with this

preference for the common good.

Public authorities in France have set a security of supply

target corresponding to an annual loss of load expectation

of three hours. Since this target is not internalised by the

energy market, there is no reason for the level of security of

supply spontaneously created by the market to match the

energy policy objective. This means that, if a decision is made

to increase or decrease the security of supply target, energy

prices will not increase or decrease accordingly: there is no

communication channel between public policy targets and

market results.

Since the market on its own will fail to meet policy objectives, it

is necessary and justifi ed for public authorities to intervene to

ensure that the market meets public policy targets and does so

at the lowest possible cost.

1.1.4

Imperfections of the energy market in terms of managing investment dynamics

1.1.4.1 Theory of investment cycles in power systems

As discussed in § 1.1.2, a more accurate representation of mar-

ket stakeholders’ behaviours allows a more accurate representa-

tion of the dynamic functioning of deregulated power systems.

Generally speaking, this challenges the idea that the market

alone can optimise investments and shows that the long-term

equilibrium suggested by theoretical analysis is rarely found in a

more realistic, dynamic model.

In the real world, a number of factors must be incorporated

into any model of investment dynamics: market stakeholders’

strategies and decision-making processes, the time requi-

red to build new generation capacities, the irreversibility of

investments and their lifespan and uncertainty surrounding

exogenous variables. More specifically, capacity investments

and retirements are not spontaneous, but rather have their

own cyclical dynamics. These cycles are created by a sort of

viscosity when it comes to bringing new generation capacities

online or removing them from the market: investments are

“triggered” (usually by several stakeholders at once) beyond

a certain level of projected profitability, and retirement deci-

sions are made below a loss threshold, here again by various

stakeholders at once. Real-life power systems thus oscillate

Quantity (GW)

Price (€/MWh)

Hours of operation

Price (€/MWh)

Peak capacity

Peak VC

VoLL

Peak VC

VoLL

Load shedding

Price cap Price cap

Missing money, decline in inframarginal rent due to price decrease during load shedding

Inframarginal rent restored through increase in load shedding/decreasein installed peak capacity

Missing money problem: Price decrease during load shedding

Increase in load shedding/decrease in installed peak capacity

Merit order Price duration curve Optimal load shedding

Functioning, optimal case

Inframarginal rent, optimal case

Functioning, missing money problem not corrected

Inframarginal rent, missing money problem not corrected

Figure 2 – Eff ects of missing money problem caused by market imperfections on the merit order and price duration curve in the energy market

24

around the long-term equilibrium, which can also evolve

depending on demand, the costs associated with different

technologies, etc.

Similarly to other capital-intensive industries with highly

variable demand (e.g. aluminium), power systems are subject

to investment cycles19. This “boom and bust” phenomenon

is characterised by periodic waves of capacity investments

or retirements. Investment cycles result in an alternation

between phases of overcapacity and under-capacity on the

system, with the “first best case” equilibrium never being

achieved.

At first, the industry may be short of capacity and prices will be

high. This acts as a signal to investors, who start to add capa-

city. In the absence of a coordination device, however, they

are in danger of over-reacting – too many investors read the

high prices as a signal that their own investment will be profi-

table. Once the new capacity comes on stream, it will depress

prices. This will be sufficient to halt most new investments,

but the existing capacity is likely to stay in service. Scrapping

decisions are irreversible and will not be taken unless the

price falls sufficiently below the variable costs of staying in

operation20.

Investment cycles are intrinsic to power systems, owing to their

specific characteristics, to how related markets function, and to

the processes capacity investment and retirement decisions

entail. The economic literature offers two very general expla-

nations of why investments are cyclical: lead times for building

capacity (time lag between investment decisions and availabi-

lity of new capacity) and suboptimal levels of information and

coordination.

These two explanations are clearly verified in power

systems in energy-only markets since energy prices

are the main means of sending information and

coordinating decisions. Cycles are notably amplified

by the fact that energy prices alone do not seem

to accurately convey information to coordinate

investments, even when additional communication

channels are created, such as the Adequacy Fore-

cast Report, which provides aggregated information

about the supply-demand balance outlook (see

§ 1.2.1).

This reflects the difference between the time

constants of investments, which are particularly

long (typically several years for decisions to be implemented,

investment lifespan of several decades) and those of energy

markets, the liquidity of which is limited except for timescales

close to real time. The lifespans and capital intensity of gene-

ration assets also limit the ability to constantly re-optimise the

generation mix as fundamentals evolve. It is impossible for the

structure of the mix to readapt.

[E]xpectations need time to be updated to the new mar-

ket conditions, investments are delayed under uncertainty,

and power plants need usually a long time to be construc-

ted and to be brought online. Under these conditions, it

is to be expected that power markets experience business

cycles, i.e. periods of huge investment rates followed by

other periods with no investment activity. This might result

in severe fluctuations of the reserve margin, and therefore

of power prices21.

These representations suggest that when the market functions

naturally, decision-making will be amplified and concentrated22.

Investors will tend to overreact to price signals and may adopt

copycat behaviours that intensify investment waves23.

1.1.4.2 Consequences of the existence of investment

cycles

The existence of capacity investment and retirement cycles

in energy-only markets is not a problem in and of itself, if

the security of supply target set by public authorities is met.

However, a succession of cycles can result in wide swings

between overcapacity and under-capacity. This in turn has

adverse consequences for security of supply and economic

efficiency.

Phases of under-capacity can lead to excessive risk of load cur-

tailment, possibly driving security of supply down to particularly

low or even socially and politically unacceptable levels. Actual

under-capacity situations would also have harmful effects on

the economy, as the cost of unserved energy could rise to very

high levels.

Cycles increase the number of periods of investments and reti-

rements. All other things being equal, generation capacities

remain on the market for a shorter time than in an optimal situa-

tion and investment needs are greater, driving up costs to final

consumers. There can thus be an economic benefit to regula-

ting cycles.

19[Ford, 1999 and 2002], [De Vries, 2004], [Green, 2006], [Cepeda, 2011]

20[Green, 2006]

21[Olsina et al., 2006]

22The recent wave of investments in CCGT plants in Europe, described in section 1.2 of this report, illustrated this phenomenon.

23[Stoft, 2002], [Knittel & Robert, 2005]

25

WHY A CAPACITY MECHANISM IS NECESSARY / 1

24This mission is described in the decree of 20 September 2006.

The theoretical model on which power market deregulation in France and Europe has traditionally been based is that of the energy-only market. Initial analysis suggests that the model can optimise the functioning of generation assets and perfectly regulate the investments needed to ensure adequacy over the long term. However, this result is based on strong and unrealistic assumptions, chief among them that the market will efficiently manage shortage situations and that price spikes will occur. Wider spread use of demand response to increase demand-side flexibility could make the energy-only model more valid, but will not suffice, at least over the medium term, to resolve this difficulty:

1. Even in an energy-only market that functions perfectly, security of supply is a public good, meaning that public authorities should define a security of supply criterion;

2. There is no reason for the energy-only market to internalise this security of supply criterion: public authorities are therefore justified in implementing a mechanism to ensure that the criterion will be met by rewarding stakehol-ders for their contribution to reducing the shortfall risk.

In sum, the capacity mechanism is part of an effort to correct an identified market failure by internalising positive externalities affecting security of supply. It is totally legitimate from an economic theory standpoint.

If this market failure is not corrected, there is no reason why some capacities that are indispensable to the functio-ning of the power system will be made available during periods of peak demand. It is also possible that energy mar-ket prices will not efficiently coordinate market stakeholders’ decisions, leading to very intense investment cycles that reduce overall economic efficiency and can result in a rapid succession of phases of overcapacity and periods when security of supply is at risk.

instruments to efficiently regulate these cycles, enabling excess

capacity to be absorbed proportionately and then investments

to resume (§ 1.2.3).

1.2.1 Assessment of security of supply risks

1.2.1.1 Risks to security of supply

This is not the first time consistent and public efforts are being

made in France to monitor risks to security of supply. RTE was

among the first transmission system operators (TSOs) in Europe

to conduct such an analysis. This mission was entrusted to it by

the law of 10 February 2000, which marked the beginning of the

deregulation of the French energy sector24. Its work is backed by

a methodological approach and recognised expertise in supply-

demand balance simulations.

Adequacy forecasts are one of the crucial assessment tools that

must be made available to public authorities when it comes to

security of supply. The European Commission has placed heavy

emphasis on this necessity in recent months:

Member States should carry out a full analysis of

whether there is a lack of investment in gene-

ration, and why. They should seek cross-border

The analyses above show that, on a theoretical level, the ability

of energy-only markets to efficiently guarantee security of sup-

ply is doubtful. This conclusion would nonetheless be insuffi-

cient if not backed by a factual analysis of the situation.

France already has the instruments required to measure security

of supply and conduct assessments prior to introducing correc-

tive measures. These instruments meet the objectives set out

in the European Commission guidelines published in November

2013 and analysed in chapter 10 of this report. They can also be

used to illustrate how safety margins are gradually decreasing,

as peak demand continues to increase (§ 1.2.1).

Such considerations must be weighed against the difficulties

many generators and demand-side operators are having in

earning adequate remuneration. At a time when the econo-

mic fundamentals of the sector are changing profoundly, the

energy-only market can no longer drive investment efficiently.

Assumptions that new investments would follow the shutdown

of existing plants, or that consumption will start to trend higher

again, do not seem certain in the current context (§ 1.2.2).

Lastly, the existence of investment cycles has also been pro-

ven. The capacity mechanism will give public authorities new

1.2 Concrete consequences of energy market imperfections

26

is sourced. These factors vary widely from one country to the

next. In France, the main risk stems from the existence of a peak

demand phenomenon.

Power demand is very temperature-sensitive in France. The ade-

quacy studies conducted by RTE27 show that temperatures are

the dominant variable for the French power system. As a result,

peak demand periods are observed in winter during cold spells,

and the phenomenon has grown steadily more intense in the

past decades.

France concentrates almost half of the total temperature-

sensitive power demand in Europe, with some 2,400 MW of

additional consumption per degree Celsius.

[…]

Temperature sensitivity has been rising steadily over the

past ten years. The winter gradient increased by more than

30% between the winter of 2001-2002 and the winter of

2012-201328.

This phenomenon is all the more important in assessing supply-

demand balance risks in France as peak demand is growing fas-

ter than power demand in general. In other words, keeping peak

demand growth in check is a primary concern, especially while

the energy transition is under way and electricity continues to

substitute other energy uses.

solutions to any problems they find before planning to inter-

vene. Any capacity mechanism needs to take into account

any impact the intervention will have on neighbouring Mem-

ber States and on the internal energy market. Fragmentation

of the internal energy market must be avoided25.

The framework for preparing adequacy reports within Mem-

ber States was further strengthened with the European Com-

mission’s publication in November 2013 of guidelines on

public intervention in the electricity market26. These guidelines

included a checklist of criteria considered relevant in assessing

capacity adequacy.

The criteria and methodology RTE uses in its Adequacy Fore-

cast Reports are discussed in detail in chapter 10 of this report.

Analysis shows that the adequacy studies conducted in France

meet the criteria established by the European Commission. And

RTE goes beyond minimal compliance: its Adequacy Forecast

Reports are among the only reports that are made public and

based on a Europe-wide and probabilistic model of the supply-

demand balance. The conclusions of these reports can thus be

cited to justify public intervention.

1.2.1.2 Specific characteristics of peak demand in France

Factors that can put security of supply at risk include climate

conditions, the structure of power demand and where energy

25[EC, 2012]

26[EC, 2013a]

27[RTE, 2012]

28[RTE, 2013]

29[RTE, 2012]

Figure 3 – Growth in peak demand in France since 200129

70,000

80,000

90,000

100,000

110,000

102,

100

100,

655

96,7

10

94,6

00

93,0

80

92,4

00

91,8

20

90,3

00

88,9

60

86,2

80

86,0

20

84,7

10

83,5

40

83,4

90

82,1

40

79,7

30

79,7

10

79,5

90

78,6

60

77,4

40

77,0

30

76,1

30

74,9

00

MW

Day

11/1

5/20

01

12/1

0/20

01

12/1

1/20

01

12/1

2/20

01

12/1

3/20

01

12/1

7/20

01

12/0

9/20

02

12/1

0/20

02

01/0

7/20

03

01/0

8/20

03

01/0

9/20

03

01/2

6/20

05

02/2

8/20

05

01/2

7/20

06

12/1

7/20

07

01/0

5/20

09

01/0

6/20

09

01/0

7/20

09

02/1

1/20

10

12/1

4/20

10

12/1

5/20

10

02/0

7/20

12

02/0

8/20

12

27

WHYACAPACITYMECHANISMISNECESSARY / 1

1.2.1.3 Analysis of the conclusions of the 2013

Adequacy Forecast Report update

Adequacy assessments are conducted in France by simulating

the operations of the power system over 8,760 hours a year for

the next fi ve years, factoring in various technical parameters

such as the dynamic operating constraints of generation units.

These are stochastic simulations based on a large number of

supply and demand scenarios. They are used to identify the

confi gurations of the supply-demand balance during shortfall

periods, i.e. situations when the level of supply modelled does

not cover forecast demand. The shortfall volumes yielded by

these simulations are then compared to the secu-

rity of supply criterion set by public authorities,

which corresponds to an average annual loss of

load expectation of three hours30.

The Adequacy Forecast Reports published since 2009 have

highlighted many diff erent phenomena, including a wave of

investments in combined-cycle gas turbine plants, the eff ects

of the economic crisis and the upward trend in peak demand.

The most recent Adequacy Forecast Report update (2013) spe-

cifi cally emphasised the gradual but steady reduction of safety

30Decree of 20 September 2006.

31[RTE, 2013]

Excerptsfromthe2013AdequacyForecastReportupdate

Under the “Baseline” demand scenario, and based on the information currently available about generation capacity over the

period considered in the report, the shortfall criterion defi ned in decree 2006-1170 of 20 September 2006 (annual loss of load

expectation of up to three hours) is not exceeded before or during 2018.

The less favourable economic outlook factored into the “Low” scenario would strengthen this conclusion. Conversely, a sharper

economic rebound, as called for in the “High” scenario, could cause the shortfall criterion to be exceeded in 2016.

Though the situation forecast in the “Baseline” scenario may seem comfortable, given the power available through imports, the

risk should nonetheless increase, particularly after 2015. As such, capacity margins above and beyond the criterion […] should

decrease by almost 6 GW over the next three years. […]

This analysis of margins also allows for […] an assessment of the potential impact of the shutdown of other fossil-fi red facilities, for

instance combined-cycle gas turbine plants, which would result in an increase in the shortfall risk31.

Figure 4 – Margins and capacity shortfalls under diff erent scenarios in the 2013 Adequacy Forecast Report update

Mar

gin

Cap

acit

y sh

ortf

all

GW

-8

-7

-6

-5

-4

-3

-2

-1

0

1

2

3

4

5

6

7

8

2014 2015 2016 2017 2018

5.8

4.8

-2

4.5

3.2

-3.4

0.4

-1.3

0

-1.9

0

1.8 1.92.2

3.23.6

4.2

-2.3

-6.5-7.2

-6.8

“Low” scenario with exchanges “Stronger DSM” scenario with exchanges “High” scenario with exchanges

“Baseline” scenario with exchanges “Baseline” scenario without exchanges

28

margins vis-à-vis the security of supply criterion, and suggested

that margins would be eliminated in 2017. One potential

consequence is that security of supply would not be gua-

ranteed in the event of an intense cold spell.

Security of supply must therefore be monitored in France.

This conclusion is all the more important considering that the

assessments conducted in 2013 already factored in a downward

revision of demand forecasts due to the ongoing effects of the

economic crisis in Europe and France. Sluggish demand eases

tension in the supply-demand balance, but will also overlap with

a significant reduction in generation capacity late in 2015, when

several fossil-fired plants will be decommissioned after new

environmental standards take effect. At the same time, some

generation capacities are facing economic difficulties, notably

combined-cycle gas turbine plants. The existence of risks thus

seems clear.

There are factors that could change this perception over the

medium term:

> Demand could prove even weaker than anticipated, which

would improve the outlook;

> Some generation units that will be affected by new environ-

mental regulations could make specific investments that

allow them to operate beyond 2015 under the new

standards: this would also make the situation less

worrisome;

> Existing units, notably combined-cycle gas turbine

plants, could be decommissioned for economic

reasons and definitively retired or mothballed,

which would darken the outlook.

The latter possibility is a crucial aspect of current

assessments. Indeed, adequacy forecasts are based

on information that is public, i.e. officially announced

by generators. The update prepared in July 2013

therefore did not take into account any shutdowns

not included in the baseline scenario, as it was based

on public information available at the time. Given

the unlikelihood that these units will become pro-

fitable, decommissioning cannot be ruled out. This

could create a negative margin vis-à-vis the criterion

if the shutdowns are not simultaneously offset by

the creation of new generation or demand response

capacities. Regulating the structural adjustment of

the mix going forward is one objective of the capa-

city mechanism.

1.2.2 Impact on capacity remuneration

Public intervention to ensure security of supply must be based

first and foremost on an assessment of the aggregate supply-

demand balance, as outlined in the section above, and not on

concerns about generators’ remuneration. There can be many

reasons for remuneration to be lower for some units, as dis-

cussed in the box in section 1.1.2, and it is not easy to identify

with certainty when the culprit is the theoretical missing money

problem and when other factors are responsible. Nonetheless,

the energy market’s ability to assign the proper value to genera-

tion, demand-side and storage capacities is a key consideration

when analysing failures in the energy market. Legitimate ques-

tions are now being raised about whether this market model,

developed in the 1980s and implemented in the 2000s, can

adapt to the changing cost structure of generation and demand

response32.

1.2.2.1 Stakeholders’ positions

More and more European energy firms are concerned about the

functioning of the market. Responses to the European Commis-

sion’s consultation on making the internal market work33 amply

demonstrated this34.

Their positions were further strengthened in May 2013 when

eight energy utilities (GDF Suez, E.ON, Eni, RWE, Enel, Gasterra,

Iberdrola and Gasnatural Fenosa) launched a “call to EU leaders

for a revitalised energy policy”, outlining the challenges firms in

The conclusions of the Adequacy Forecast Report are based on accurate analyses that meet the criteria set forth in Directive 2005/89/EC and expanded on by the European Commission in November 2013. These analyses are the tool used by RTE and public authorities in France to assess the security of supply outlook.

Though the regulatory warning threshold is not exceeded over the period under review, the 2013 Adequacy Forecast Report update points to a gradual and steady decline in margins over the period, and the disappearance thereof from 2017, meaning that security of supply risks will indeed increase in France and Europe.

If capacity retirements or demand growth exceed the levels factored into the Adequacy Forecast Report “Baseline” scenario, then security of sup-ply would decline to a level that is unacceptable with regard to the criterion defined by public authorities.

32Within [General Commission for Strategy and Foresight, (CGSP),2014], see the contribution of Fabien Roques, “European electricity markets in crisis: diagnosis and way forward”.

33[EC, 2012a]

34[GDF Suez, 2013] A general decrease in the load factor of thermal power plants […] is undoubtedly endangering the investments in new conventional plants which are urgently needed by the power system. Even more worrying is the reality that existing thermal power plants, built in an open market system without support schemes (as opposed to out-of-the-market RES) no longer reach the expected profitability and may have to be prematurely decommissioned due to profitability concerns.

29

WHY A CAPACITY MECHANISM IS NECESSARY / 1

the power sector are facing. This initiative, which other energy

companies with the same concerns have since joined, is now

called the “Magritte Group’’. It has called for a Europe-wide capa-

city mechanism that would recognise the value of capacity as a

safeguard.

In concrete terms, European energy companies are experien-

cing a perfect storm, which is endangering security of supply

and the transformation towards a low-carbon economy, as

well as undermining their capacity to attract capital35.

More recently, Union française de l’électricité, the French power

industry’s trade body, mentioned in its response to the public

consultation on energy and environmental State aid how diffi-

cult it had become for energy-only markets to internalise the

value associated with security of supply.

These concerns are shared by public authorities in many Mem-

ber States, including France:

Wholesale electricity prices alone do not provide sufficient

remuneration to ensure the long-term future of existing

peak generation capacities, or to trigger new investment in

generation or demand response capacities. Some plans to

build combined-cycle gas turbine plants in France have been

scrapped (notably in Hornaing), and others are running into

economic troubles36.

Delays and cancellations of new capacity projects are tangible

manifestations of these concerns, as are shutdowns and plan-

ned retirements of existing capacities for economic reasons:

Elsewhere in Europe, economic and market conditions for

combined-cycle gas turbine plants are similar to those obser-

ved in France. Some generators have already announced

plant shutdowns, and other facilities could be mothballed.

The Adequacy Forecast Report takes into account the shu-

tdowns announced and assumes that no new capacities will

be commissioned outside France over the period considered

in the report37.

1.2.2.2 Analysis of the situation

Current discussions about the failures of the energy-only mar-

ket often focus, in Europe, on the problem of the viability of

combined-cycle gas turbine plants (and, in France, on the eco-

nomic space created for demand response). Massive invest-

ments have been made in this type of facility in Europe in recent

years. Today, different studies show that prices on the wholesale

market do not allow operators to cover their total

fixed costs, and they are barely able to cover their

fixed operating costs38. Some thus see capacity

mechanisms as a means of ensuring that operators

can “cover their fixed costs”, since their results in the

market barely “cover variable costs”.

The problems currently seen with capacity remune-

ration are nonetheless probably of a different order,

and are largely due to shocks external to the electri-

city market or inconsistencies between regulatory

tools39:

> The economic crisis, combined with a failure to

anticipate the impact of new energy efficiency

standards and the introduction of shale gas into

the global energy equation, have caused demand

for all energy sources to contract and reversed

the merit order between gas- and coal-fired faci-

lities in Europe;

> The currently low price of CO2 emission certifi-

cates has not offset this evolution of economic

fundamentals;

> The development of renewable energies, driven by support

mechanisms outside the market, has driven energy market

prices down and blurred investors’ perception of prices. These

support mechanisms have led to a massive development of

generation capacities independently of the dynamics of the

electricity market. As a result, investments in generation capa-

cities are being shaped by two different dynamics: one that fol-

lows market signals, and one that follows regulatory incentives.

In a word, generation capacity remuneration problems cannot

all be blamed on energy market imperfections.

As regards demand response capacity, concerns about whether

there was sufficient economic space for it to develop underpin-

ned the proposals made in the Poignant-Sido report to address

the shortcomings of the energy-only market40.

1.2.2.3 Incentives to invest in peak generation

capacities

The current debate in Europe about the profitability of certain

generation assets has a special resonance in France, due to the

specific characteristics of its power sector, and notably the peak

demand phenomenon described earlier.

Peak demand periods are not necessarily a problem if they

reflect what the system needs physically to meet demand and

35Press release: “Call of eight leading energy companies to EU leaders for a revitalised energy policy”, 21 May 2013.

36[French Republic, 2013]

37[RTE, 2013]

38[General Commission for Strategy and Foresight, (CGSP),2014], IHS CERA estimated in a recent report that out of the 330 GW of thermal plants in operation in EU-27 countries, almost 113 GW (about 38%) are at risk of closure within the next three years in the absence of electricity market reforms.

39[Keppler et al., 2013]

40[Poignant-Sido, 2010]

30

if the resources used to meet that demand are eco-

nomically proportionate to the collective benefi ts to

consumers. The phenomenon does, however, pose

some diffi culties in terms of threats to the supply-

demand balance and security of supply, the costs

incurred to meet demand and how eff ectively mar-

ket signals respond to these consumption needs.

Indeed, satisfying peak demand requires having enough gene-

ration and/or demand response capacities available to balance

supply and demand in real time. The energy market must in fact

send the right economic signals to encourage suffi cient invest-

ment to ensure that these capacities will exist and be available.

In its current form, the electricity market has not been able to

create adequate incentives in such situations. This point was

notably made in the Poignant-Sido41 report of 1 April 2010,

which was based on the fi ndings of a workgroup that brought

together all power sector stakeholders under the aegis of two

parliamentarians. The workgroup specifi cally studied trends in

the structure of demand and peak demand in France, and the

report concluded that:

Eff orts to secure fi nancing [for demand response and peak

capacity] exclusively through the energy market are doomed

to fail since, though energy markets can in theory ensure that

peak capacity – and similarly demand response – is profi table,

they do not off er enough visibility. The timing and scale of price

spikes are too random and the risks are too high for investors.

Peak demand is not unpredictable. Adequacy assessments

illustrate the risk posed to the supply-demand balance by cold

spells. RTE’s most recent Adequacy Forecast Report shows that

by 2017, due to the erosion of margins, the French power sys-

tem would not be able to withstand a cold spell of the same

magnitude as that seen in 2012. Given these forecasts and the

fact that the peak demand phenomenon is predictable, it is cru-

cial to ensure that suffi cient generation or demand response

capacities are available to meet power demand when security

of supply is at risk. If security of supply is to be guaranteed, then

the required capacities must be eff ectively available during

these periods.

1.2.3 Existence of investment cycles

As discussed in §  1.1.4, the power sector has specifi c charac-

teristics that are conducive to investment cycles. Such cycles

have been observed in numerous countries:

[S]ome electricity markets running under competitive

rules have experienced periods of excess of investments,

and therefore over-capacity, such is the case of UK with a

large entry of private investors relying on gas-fired power

plants. Others have already experienced long periods with-

out new capacity additions that have ultimately led the

market to under-capacity conditions. Such was the case of

California during the electricity crisis in the summers 2000

and 200143.

Events in California convinced many that additional measures

were required to ensure that suffi cient investments were made

in deregulated electricity markets in the United States.

Investment cycles have also occurred in other contexts. Below

are examples of investment cycle phenomena observed in dere-

gulated energy markets.

41[Poignant-Sido, 2010]

42[Arango & Larsen, 2011]

43 [Olsina et al., 2006]

Figure 5 – Trends in power system reserve margins in Chile, Britain and Scandinavia (diff erent scales)42

0.7

0.6

0.5

0.4

0.3

0.21984

Res

erve

Mar

gin Reserve Margin

Smoothed Value

Chile

1988 1992 1996 2000 2004 2008

0.55

0.45

0.35

0.251988

Res

erve

Mar

gin

Reserve Margin

Smoothed Value

Nordpool

1992 1996 2000 2004 2008

0.35

0.30

0.25

0.20

0.151988

Res

erve

Mar

gin

Year

Reserve Margin

Smoothed Value

England and Wales

1992 1996 2000 2004 2008

31

WHY A CAPACITY MECHANISM IS NECESSARY / 1

The massive investments made in combined-cycle gas turbine

capacity in Europe between 2004 and 2012 can be conside-

red as characteristics of a phase of excess investment, though

subsequent developments moved things in a radically different

direction:

In the EU-27, some 12% of gas-fired capacity could be taken

off line within three years. These plants are nonetheless

crucial to the equilibrium of the system, which will have

to accommodate increasing penetration of intermittent

and unpredictable renewable energy sources. At the same

time, significant investments will have to be made to update

ageing infrastructure. Several large operators facing serious

financial trouble  – who have seen their net debt double

in the past five years  – will have a hard time meeting this

challenge45.

The phenomena described above have thus been observed in

France and elsewhere in Europe, particularly after the recent

wave of investments in combined-cycle gas turbine plants.

These massive investments have led to a paradoxical situation:

the combined effects of sluggish demand, generators’ failure

to anticipate the impact of new environmental standards and

renewable support mechanisms have created a temporary

situation of excess capacity, but the opposite could happen

suddenly if loss-making plants are retired simultaneously, in

spite of the steep investments made to maintain the supply-

demand balance.

In other words, the phenomenon of alternating phases of

overcapacity and under-capacity appears to be playing out,

creating a risk that many plants will be decommissioned well

before the end of their useful life, suddenly putting security of

supply at risk.

The French capacity mechanism will help regulate the

transition from a situation of overcapacity to one in which

security of supply could be at risk. The analysis above is not

based on a naïve approach to the market, postulating a perfect

functioning of the market where failures have been identified

in theory or in practice, or on a dogmatic challenge to the mar-

ket’s ability to drive investment. On the contrary, the analysis

RTE conducted and submitted to public authorities focuses on

the fact that security of supply risks are moderate for now, but

stresses the instability of this analysis and its significant sen-

sitivity to parameters outside the French power sector. It also

emphasises the peak demand phenomenon in France, this

being the biggest challenge to address and the

one on which public intervention should be based.

The capacity mechanism will need to look in detail

at the characteristics of this phenomenon and

offer solutions for managing it effectively.

44Source: Platts PowerVision

45[CGSP, 2014]

Figure 6 – New combined-cycle gas turbine capacity in Europe44

GW

0

5

10

15

20

25

30

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

France

Norway

Germany

Poland

Austria

Greece

Portugal

Belgium

Hungary

Romania

Bulgaria

Ireland

Slovakia

Croatia

Italy

Slovenia

Cyprus

Latvia

Spain

Czech Republic

Lithuania

Sweden

Denmark

Luxembourg

Switzerland

Finland

Netherlands

United Kingdom

32

1.3 Projected trends in demand over the coming years

Above and beyond the energy market failures described above,

the physical needs of power systems in France and Europe are

also changing dramatically, and these changes could result in

additional market failures.

To achieve the energy transition targets set by the European

Union, the power system must be adapted to accommodate a

huge and growing quantity of renewable energies. This makes

it even more necessary to have flexible technologies – either in

the form of generation or demand response capacities – to gua-

rantee that electricity supply and demand will balance.

An analysis of these trajectories leads to two observations: first,

significant investments will have to be made in the power sec-

tor, bearing in mind that the peak demand phenomenon could

continue due to the increasing role public authorities want

electricity to play to help meet their energy policy objectives

(§  1.3.1), and second, increasing renewable penetration could

result in a need for more flexibility (§ 1.3.2).

1.3.1 The growing role played by electricity in achieving energy policy objectives

Europe is engaged in a far-reaching energy transi-

tion process. The European Council has set a target

of reducing greenhouse gas emissions by 80 to 95%

from the 1990 level by 2050. The European Com-

mission analysed the implications of this target in

its “roadmap for moving to a competitive low-car-

bon economy in 2050”47. Several industry-specific

roadmaps have followed, notably the “Energy Road-

map 2050”48, in which the Commission examines

the challenges of achieving the Union’s decarbonisation target

while also safeguarding security of energy supply.

The energy sector produces the lion’s share of man-made

greenhouse gas emissions. Therefore, reducing greenhouse

gas emissions by 2050 by over 80% will put particular pres-

sure on energy systems49.

The Energy Roadmap 2050 explores different ways to make the

energy transition happen and lists ten structural changes power

systems will have to undergo under any decarbonisation scenario.

Among these unavoidable structural changes, two are worthy of

particular note: the increasing role to be played by electricity

and the increasing role of renewables in the energy mix.

Electricity plays an increasing role.

All scenarios show electricity will have to play a much grea-

ter role than now (almost doubling its share in final energy

demand to 36-39% in 2050) and will have to contribute to the

decarbonisation of transport and heating/cooling.

[…]

Final electricity demand increases even in the High energy

efficiency scenario. To achieve this, the power generation sys-

tem would have to undergo structural change and achieve a

significant level of decarbonisation already in 2030 (57-65%

in 2030 and 96-99% in 2050).

Renewables rise substantially

The share of renewable energy rises substantially in all scena-

rios, achieving at least 55% in gross final energy consumption in

2050, up 45 percentage points from today’s level at around 10%.

46Given the time constants involved in developing new generation capacity and adapting the power system as a whole, 2017-2018 is the very near future.

47[EC, 2011a]

48[EC, 2011b]

49[EC, 2011b]

The imperfections of the energy market described in academic literature can also be observed in real markets:

> Forward analyses of the security of supply situation in France show that margins will decrease and then be elimi-nated in the near future46;

> It appears that energy markets alone are not guaranteeing the profitability of capacity;

> The existence of investment cycles in power markets has been demonstrated in many cases and countries.

In sum, the failures of energy markets have been characterised and supporting evidence has been gathered from actual operations. These failures raise questions about the ability of a market model first used in the 2000s to adapt to the changing cost structure of generation and demand response capacities. They support the idea that more must be done to guarantee security of supply and the proper economic functioning of electricity markets.

33

WHYACAPACITYMECHANISMISNECESSARY / 1

50[EC, 2011b]

51[EC, 2011b]

52The EU-ETS (EU Emissions Trading Scheme) is the European market for trading carbon emission permits.

53Directive 2009/28/EC.

[…]

In 2030, all the decarbonisation scenarios suggest growing

shares of renewables of around 30% in gross fi nal energy

consumption50.

Energy transition policies have direct consequences for the

functioning of energy markets and the security of supply tar-

get. However, these changes are not meant to be antithetical to

security of supply or economic effi ciency targets, as the Euro-

pean Commission points out in the Energy Roadmap 2050:

There will be no compromise on safety and security for either

traditional or new energy sources. The EU must continue to

strengthen the safety and security framework and lead inter-

national eff orts in this fi eld.

[…]

These create new challenges to power markets in the transi-

tion to a low-carbon system providing a high level of energy

security and aff ordable electricity supplies. More than ever

should the full scale of the internal market be used.

[…]

One challenge is the need for fl exible resources in the power

system (e.g. fl exible generation, storage, demand manage-

ment) as the contribution of intermittent renewable genera-

tion increases. The second is the impact on wholesale market

prices of this generation. Electricity from wind and solar has

low or zero marginal costs and as their penetra-

tion in the system increases, in the wholesale

market spot prices could decrease and remain

low for longer time periods51.

In other words, a tool is needed to effi ciently

guide the energy transition while safeguarding

security of supply and ensuring that electricity mar-

kets function properly.

Policy objectives aimed at reducing Europe’s carbon footprint

and diversifying its energy sources go beyond the integration

of the power sector into the EU-ETS52 mechanism, which in

theory must send the right signals for investing in technologies

with lower greenhouse gas emissions. In accordance with the

“20-20-20” objectives set by the European Council in 2007 and

translated into the “Renewable Energies” directive53 of 2009, all

Member States have identifi ed trajectories for the penetration of

renewable energies and implemented sector policies to support

them. These policies are very much a driving force in investment

dynamics within Member States today, as was discussed earlier.

Some eff orts to reshape the electricity mix have focused on

other technologies. The president of the French Republic has

committed to reducing the share of nuclear power in the mix to

50% by 2025, which should result in some existing plants being

Figure 7 – Trend in installed wind and solar power In France and targets for 2020 (Source: Data on grid connections taken from the Panorama des énergies renouvelables 2013 prepared by RTE, SER, ERDF and ADEEF).

MW

0

5,000

10,000

15,000

20,000

25,000

30,000

2001 2002 2003 2004 2005 2006 2007 2008 2009 20112010 2012 2013 … 2020*

* Estimated contribution of different technologies to the binding target for 2020 set in the National Renewable Energy Action Plan

  Wind power connected (MW)

  Photovoltaic power connected, cumulative (MW)

34

The implementation of a capacity mechanism in France is

not a standalone initiative. In an effort to correct the imper-

fections of the energy market and meet the requirements of

the energy transition and safeguard security of supply, the

existing model is gradually being strengthened and added

to in order to close all gaps identified. Some of the changes

being made aim to improve how existing electricity markets

function.

The various mechanisms in question were inspired by seve-

ral proposals contained in the Poignant-Sido report54 and the

architecture described in the “target model” for the

European energy market, which notably call for:

> The integration of electricity markets on all timescales and the

development of interconnections (§ 1.4.1);

> The integration of demand and demand response into mar-

kets (§1.4.2);

> The overhaul of renewable energy support mechanisms (§1.4.3);

> The capacity mechanism (§1.4.4).

1.4.1 Ongoing integration of energy markets

European energy market integration requires the continued

development of mechanisms for all timescales, and it must be

ensured that physical infrastructure does not impede the inte-

gration process.

shut down before then. Germany’s Energiewende policy and

decision to phase out nuclear power are another example.

With public authorities directly involved in expanding or reducing

the role of specific technologies, it seems the market will have

to regulate the adjustment of the rest of the electricity mix, or in

other words to drive a series of investments and retirements to

readapt the mix to reflect energy policy changes without jeopardi-

sing the government’s security of supply targets. The implemen-

tation of a capacity mechanism will address this need by crea-

ting more visibility and introducing a feedback loop with public

security of supply objectives into the market architecture.

1.3.2 Growing need for flexibility in European power systems

The penetration of renewable energy sources like wind and solar

power is increasing the level of intermittency in the generation

mix. This does not pose any particular problems while pene-

tration rates are low. Over the long term it will result in a need

for more flexible capacity to offset weather-driven variations in

renewable energy output. More flexibility will be required not

only of generation assets but also of demand response capaci-

ties and, more generally, all technologies that can modulate the

load curve, for instance storage.

What this is creating is a gradual shift from a need to have capa-

cities that are available to a need to have capacities that are both

available and flexible. Discussions held at the European level in

recent months have taken this shift into account, and the need

for greater flexibility is now recognised.

Wind and solar penetration rates in France are relatively low

compared with some European countries like Germany, such

that the balancing mechanism suffices, for now, to ensure ade-

quate flexibility. Capacity needs still focus specifically on peak

demand, which is the biggest unknown for the French power

system and should remain so in the years to come.

The Government has nonetheless set ambitious targets for the

penetration of intermittent energy sources and, over time, the resul-

ting change in the generation mix could create the need for more

flexibility. Bearing this in mind, the capacity mechanism rules must,

from the beginning, factor in the possibility that the fundamentals

of security of supply will evolve and ensure that adjustments can be

made to reflect a change in risk levels. This concern was taken into

account during the drafting of the rules, which acknowledge the

possibility that flexibility needs could change going forward.

54[Poignant-Sido, 2010]

The energy transition represents a major chal-lenge, and the energy market alone will not be able to meet all of the policy objectives set. Intro-ducing a mechanism that acts as a feedback channel with the security of supply target should help public policies efficiently drive investment while also safeguarding security of supply. The need for flexibility, which will only increase going forward, must be integrated into the mecha-nism’s design.

1.4 Efforts to reform market structures in France

35

WHY A CAPACITY MECHANISM IS NECESSARY / 1

1.4.1.1 Introduction of market mechanisms facilitating

internal energy market integration

To improve how electricity markets function, trading conditions

for all timescales must be improved by introducing the same

mechanisms and products across Europe.

Adopted in 2009, the Third Energy Package called for the fur-

ther construction of the internal market applying two comple-

mentary approaches: (i) the introduction of harmonised rules

for all of Europe, and (ii) further integration through pilot initia-

tives covering all timescales.

As a transmission system operator, RTE is particularly interested

in this work and is helping to build the internal electricity market

applying these two approaches.

RTE is notably involved in initiatives, many of them pilots, to

deploy the “target” model over all timescales at the regional

level. Two examples are CWE (Central-Western Europe) and NWE

(North-Western Europe), which have enabled day-ahead price

coupling on markets in these regions. Market participants can

now trade electricity from France to Finland and from Great Bri-

tain to Germany. Market coupling helps optimise energy trading

and the use of interconnections and is making markets more

liquid as it expands.

Where shorter timescales are concerned, the integration of

intraday markets in France, Germany, Austria and Switzerland

on 26 June 2013 was a first step towards the introduction of

implicit intraday cross-border capacity allocation. RTE is also

playing an active role in the NWE intraday project. The intro-

duction of cross-border intraday trading is a priority for the

European Commission, since it will boost the liquidity and effi-

ciency of the internal market.

To enable cross-border trading beyond the intraday period,

RTE is already participating in the creation of cross-border

balancing mechanisms. One example is BALIT (BALancing

Inter TSO), which allows transmission system operators RTE

and National Grid to exchange balancing energy (beyond

required margins). In this sense, BALIT creates more com-

petition within the balancing mechanism by bringing new

participants into national mechanisms, increasing economic

efficiency. An extension of BALIT to the South-West Europe

Regional Initiative (France-Spain-Portugal) is being finalised,

proof that interest in this type of mechanism is widespread.

The mechanism is a precursor for the development of cross-

border balancing energy trading at the European level, as

per the provisions of the Electricity Balancing

Network Code.

1.4.1.2 Integrating the internal market

through interconnection development

Grid infrastructure must keep pace with internal

market integration through market mechanisms. In its most

recent ten-year plan for grid development in continental France,

submitted for consultation in November 2013, RTE included

status reports on interconnection projects under consideration,

which could add 10 GW of exchange capacity between France

and neighbouring countries by 2025.

Of the projects being considered, five have been identified

as Projects of Common Interest, as defined in Regulation

347/201355: the three interconnection projects between

France and the British Isles, in the North Seas corridor: “IFA 2”,

the France-Alderney-Britain project and the planned intercon-

nection between France and Ireland; and two projects in the

North-South-West corridor of Europe: the Savoy-Piedmont

project and the France-Spain interconnection project in the

Gulf of Gascony. The fact that they have earned the Project of

Common Interest label underscores the key role these inter-

connections will play in achieving the objectives of Europe’s

energy policy, building the internal market, integrating

renewable energy and enhancing security of supply, as descri-

bed in Regulation 347/2013.

To meet all of the investment needs outlined in the ten-year

plan and the challenges raised by the energy transition in

France and Europe, annual transmission infrastructure invest-

ments of around 1.5  billion euros are planned over the next

ten years.

RTE is taking an active part in initiatives to conti-nue to build the internal market, improving how it operates and the quality of signals sent to mar-ket stakeholders.

These initiatives involve creating European market mechanisms covering all timescales, as required by target models, and developing new interconnection capacity.

Taken together, these efforts are contributing to the construction of the internal market, as recommended by the European Commission56.

55Regulation 347/2013 on guidelines for energy infrastructure.

56[EC, 2012a]

36

1.4.2 Participation of demand response in energy markets

To continue to build the internal market and meet the challenges

associated with the energy transition and security of supply,

demand response must be allowed to play a bigger role in energy

markets. Much progress has been made in this area in France,

which has taken a proactive approach to developing demand-

side management: as the result of a four-year programme, all

markets (energy, capacity, reserves and system services) will be

open to demand response with effect from 1 July 2014.

The Commission has voiced concerns that Member States are

not sufficiently tapping the potential of the demand side, which

it says could represent 60 GW of peak capacity (or 10% of total

peak demand in Europe).

The potential of the demand side in markets is currently

underutilised. Consumers have traditionally been considered

passive users, rather than an influential part of the energy

market. Changes in the supply side, particularly increases

in “variable” wind or photovoltaic power generation, require

more flexibility in energy networks. Changes to consump-

tion patterns, coming from energy efficiency, local energy

sources, and demand response solutions can provide such

flexibility and will be crucial for effectively matching supply

with demand in the future57.

The European Commission also expressed its attachment to the

participation of demand in energy markets, noting that Member

States are required by Directive 2012/27/EU on Energy Effi-

ciency58 to allow demand-side participation in markets.

In France, the Poignant-Sido report proposed a series of changes to

allow demand to participate in all markets, over all timescales. These

changes are being implemented in the French market to ensure

that demand response can participate and that the European Com-

mission’s recommendations are complied with to the letter.

The sections below describe briefly how the demand side can

participate in the French market. A more detailed presentation

can be found in chapter 10 of this report.

1.4.2.1 Participation of demand in the balancing

mechanism and the provision of reserves and

system services

Some types of demand response (industrial firms

connected to the public transmission system) have been

remunerated through the balancing mechanism since it was

first created in 2003.

RTE has been promoting different experiments since 2007,

under the aegis of CRE, to take better advantage of the demand

side potential:

> To encourage the aggregation of consumers’ potential to

modulate the load curve, RTE introduced the concept of the

demand aggregator in 2007, and has since then been working

to remove technical barriers to aggregation;

> An experiment launched in 2007 allows distributed demand

response to participate in the balancing mechanism, thanks

to the aggregation of residential demand (some representing

less than 1 kW).

A more recent experiment in Brittany aims to extend opportu-

nities to participate in the balancing mechanism to generation

or consumption sites that are not injection sites for the public

transmission system: they can submit balancing offers repre-

senting up to 1 MW instead of 10 MW. These offers can be acti-

vated to resolve certain grid congestion situations.

Since 2008, it has also been possible for demand response to

enter into rapid and complementary reserves contracts, as

per the provisions of article L.321-11 of the Energy Code. This

article stipulates that RTE may enter into rapid and complemen-

tary reserves contracts with generators and suppliers that can

be activated on the balancing mechanism. These contracts are

entered into based on procedures that are “competitive, non-

discriminatory and transparent”. RTE is also organising specific

tenders for demand response capacity that can be activated

through the balancing mechanism.

Lastly, specific mechanisms have been set up to allow the par-

ticipation of demand in short-term market mechanisms other

than the balancing mechanism (interruptibility contracts, speci-

fic tenders for demand response capacity).

As regards ancillary services, the new regulatory framework in

effect since 1 January 2014 calls for a gradual increase in eligible

volumes starting on 1 July 2014.

1.4.2.2 Participation of demand

in the energy market

Demand response can represent a new means of preserving

the supply-demand balance over the short and long terms. Its

integration into the energy market therefore requires specific

provisions to ensure that capacities can be effectively deployed

57[EC, 2013a]

58[EC, 2013a]

37

WHY A CAPACITY MECHANISM IS NECESSARY / 1

over different timescales (day-ahead or intraday basis) with no

discrimination vis-à-vis generation capacity.

Demand response capacities can be remunerated “implicitly”,

through private optimisation of supply portfolios. This approach

is widely used in Europe, to different extents. Explicit valuation

requires going through the energy market and is only possible

in a few countries (for instance the United States). This second

option is now available in France thanks to the NEBEF mecha-

nism (block exchange notification for demand response), ope-

rational since 1  January 2014, which allows demand response

capacities to compete with generation capacities in the energy

market.

The NEBEF mechanism implemented by RTE thus complements

the market architecture by introducing new ways to value

demand response. It allows demand-side operators to leverage

the flexibility of consumption sites to take full advantage of

short-term optimisation opportunities, since a site that reduces

its consumption can benefit directly or through a demand-side

operator from any differential between market prices and supply

prices over the same period. This makes the load curve more

flexible, including when sites are on regulated tariffs or have

entered into fixed-price supply contracts on the market.

By creating a level playing field for all stakeholders, these new

opportunities are also boosting competition within the energy

market.

In this regard, the introduction of the NEBEF mechanism by

RTE should help meet the public policy objectives set in France

and Europe for reducing energy use. For instance, the NEBEF

mechanism has made France a pioneer in implementing the

provisions of article 15.8 of the Energy Efficiency Directive of

25 October 2012.

1.4.3 Reform of renewable support mechanisms

Renewable power generation technologies have witnessed

significant growth over the past ten years thanks to support

mechanisms that offer substantial incentives. This was notably a

response to the binding renewable energy targets set by Europe,

where renewable energy sources are to represent 20% of gross

energy consumption by 2020. The EU’s objective is adapted to

each Member State: in France, renewable energy sources are

to make up 23% of gross domestic energy consumption by

2020. Member States are free to create support mechanisms to

ensure that objectives are met.

Different kinds of support mechanisms are found in Europe.

Spain has for instance opted for a premium on top of the

market price. However, a large majority of European countries

initially chose a price-based support mechanism – the feed-

in tariff  – that locks in purchase prices for renewable power

over long periods (10 to 15 years on average). The incentives

created by these mechanisms are very substantial, as gene-

rators receiving subsidies are protected not only from market

price risks but also from quantity risks, since all of the elec-

tricity they generate must be purchased and they benefit

from priority dispatch to the grid, in compliance with current

regulations.

The architecture of feed-in tariffs has created economic distor-

tions in markets, as evidenced by the periods of negative prices

seen in France and Germany (when prices are negative, genera-

tors are paid to inject electricity and consumers are remunera-

ted for consuming it). The underlying causes of negative prices

are varied and concomitant. The markets in question have also

seen a structural decrease in electricity prices and base-load

prices that have in some cases risen above peak-load prices.

Low electricity prices have led some operators to temporarily

take generation units offline, since prices failed to cover their

costs. Though these problems cannot be blamed exclusively

on renewable support policies, there is no denying that support

mechanisms that are completely disconnected from power

market dynamics only exacerbate the failures already present in

a perfect energy-only market.

The European Commission reiterated recently that Mem-

ber States’ energy policies must be properly designed. It also

stressed that support mechanisms should be compatible with

electricity markets, and even suggested that feed-in tariffs could

be scrapped and replaced by instruments that are more like

market mechanisms:

France is taking a proactive approach to deve-loping demand response capacities: after four years of efforts, all markets (energy, capacity, reserves and ancillary services) will be open to demand response by 1  July 2014. RTE’s leading role in implementing these structural changes is widely recognised.

Taken together, these actions are helping address security of supply and energy transition chal-lenges by making the load curve more flexible to ensure that consumer needs will be met over all timescales.

38

Any support that is still necessary should there-

fore supplement market prices, not replace them,

and be limited to the minimum needed. In practice,

this means phasing out feed in tariff s which shield

renewable energy producers from market price

signals and move towards feed in premiums and

other support instruments, such as quota obligations,

which force producers to respond to market prices59.

While the European Commission was conducting its analysis,

France launched a broad consultation mid-December 2013 on

potential changes to support mechanisms, asking stakeholders

to respond to a series of questions about the effi cacy of the

various mechanisms possible and the target models to be deve-

loped going forward. The purpose of this consultation is indeed

to modify existing mechanisms to make them compatible with

the electricity market.

The President of the Republic also emphasised the need to

make changes to the forms of support available to renewable

energy sources (RES). The goal is to promote their integration

into the power system and favour their development over the

long term, while ensuring a more effi cient regulation of the

power system and optimising returns on collective invest-

ments in this area. Existing support mechanisms were crea-

ted at a time when RES were just getting started (except for

conventional hydropower). They were appropriate for the

industry’s debut. But the situation has changed since, and the

mechanisms must now be improved upon60.

The consultation closed at the end of February 2014.

1.4.4 Implementation of the capacity mechanism

Introducing a capacity mechanism is a major part of France’s

eff ort to correct the structural shortcomings of the energy mar-

ket and safeguard security of supply, bearing in mind the ambi-

tious policies the energy transition involves.

The mechanism was fi rst proposed in the Poignant-Sido report

of 2010 as a way to complement existing energy market ins-

truments. The report proposed that the mechanism design be

based on a capacity obligation for suppliers as well as a capacity

market61.

French law 2010-1488 of 7 December 2010 reforming the orga-

nisation of the electricity market (NOME Act) incorporated these

proposals from the Poignant-Sido report in article 6, creating a

capacity mechanism in continental metropolitan France.

1.4.4.1 A market mechanism designed to safeguard

security of supply

The term “capacity mechanism” usually refers to any com-

plementary mechanism used in energy markets to ensure

Assessing the economic impact of the capacity mechanism

In compliance with article 20 of Decree 2012-1405, RTE will conduct a series of economic assessments that it will submit to

CRE. The decree stipulates that these assessments are to focus notably on “the integration of the capacity mechanism within

the European market”, its “interaction with the mechanisms in place in these countries”, and “improving the functioning of the

capacity mechanism”.

RTE’s studies are to include an assessment of the economic impact of various market models, including the energy-only market

and the French capacity mechanism. Economic effi ciency will notably be measured based on each market model’s ability to

coordinate investors’ decisions, using a comparative approach. Simplifi ed models – particularly of investment cycles – are docu-

mented in the academic literature and can be useful in illustrating the phenomena at work and magnitude of the stakes, both in

terms of economic effi ciency and security of supply. Once the capacity mechanism rules have been published, the parameters

of the models can be aligned with those of the actual mechanism.

In addition to being submitted to CRE, these assessments will be made public to promote a broader understanding of the eco-

nomic role the capacity mechanism will play in the design of the French and European electricity markets62.

59[EC, 2013b]

60See chapter 4 of this report.

61Proposals 16 and 17.

62[French Department in charge of Energy and Climate (DGEC), 2013]

Guaranteed feed-in tariff s in France are currently being reformed at the initiative of the Energy Minister. The review of existing support mecha-nisms is still under way and should result in subs-tantial modifi cations to the law, favouring instru-ments that are compatible with the creation of the internal energy market.

39

WHY A CAPACITY MECHANISM IS NECESSARY / 1

remuneration not based directly on energy generated. Howe-

ver, this definition might be interpreted to mean that the ulti-

mate goal of the mechanism is to provide additional revenue

for generators, or even to compensate existing plants for some

stranded costs resulting from changes in market fundamentals

or renewable support policies.

A mechanism designed solely to ensure additional revenue for

generation plants, irrespective of the actual level of security of

supply, would be inefficient. Indeed, it could end up funding

excess capacity by artificially inflating investment incentives,

which would skew market fundamentals and incentivise players

to try to secure rents (speculative investments). Conversely, if

additional remuneration is improperly calculated, the mecha-

nism might not be able to safeguard security of supply. The

European Commission has expressed concerns about such

issues63:

In liberalised markets, investments are not guaranteed by

the State. Only where there is a real threat to generation ade-

quacy and security of supply as a result of closure or mothbal-

ling does the financial viability of existing plant become a mat-

ter of public concern. It is very important that there should

not be state support to compensate operators for lost income

or bad investment decisions.

[…]

One particular concern about market wide capacity mecha-

nisms is that they can over reward generation which was

already financially viable.

[…]

establishing the correct value for capacity payments is

difficult and open to accusations of political interference.

Neither can it be assured that required capacity will be

delivered (particularly given regulatory uncertainty asso-

ciated with the setting of the payment) or alternatively that

excess capacity will not result from the scheme resulting in

overcompensation.

[…]

the chosen mechanism [should] ensure that identi-

fied adequacy gap will be filled while avoiding risks of

overcompensation.

To avoid this twofold threat of economic inefficiency and the

absence of real security of supply guarantees, the mechanism’s

design must focus not on providing additional revenue to gene-

ration plants but on safeguarding security of supply. In other

words, rather than a capacity remuneration mechanism, what

is needed is a mechanism that rewards each contribution to

security of supply in proportion to its coverage of

system needs.

If this is achieved, then the mechanism will merely

internalise in full – without going beyond that – the

positive externality represented by an operator

making available capacity that can be effectively dispatched

when supply in the power system is tight. Such a mechanism

would be justified by economic theory and compatible with

market principles if properly designed.

In its report on the European power system of January 2014,

the General Commission for Strategy and Economic Forecasting

notably alludes to the need to complement the electricity mar-

ket and assign a value to security of supply through an additio-

nal, dedicated mechanism:

The most important point may be that many recent market

reforms involving the implementation of “capacity mecha-

nisms” suggest that most governments consider security of

supply to be essential to the economy, so much so that a spe-

cific mechanism is required to safeguard it.

[…]

The current debate about capacity mechanisms focuses on

the fundamental problem that energy-only markets do not

create the right incentives for long-term investments and

cannot guarantee that there will be sufficient reserve capa-

city to preserve the equilibrium of the system under all cir-

cumstances. More specifically, most governments have expli-

cit or implicit targets when it comes to the number of power

outages they estimate consumers would willingly accept […]

and today’s energy markets do not have a mechanism to gua-

rantee that the investments required to meet this dependabi-

lity objective will be made64.

1.4.4.2 A mechanism that encourages the investments

the energy transition will require

As discussed above, the energy-only market is designed first

and foremost to create an economically efficient system: it will

not contribute to the achievement of governments’ sustainable

development objectives. Consequently, the energy market

needs an additional instrument if it is to guide the energy transi-

tion and stimulate the investments required to meet this energy

policy goal.

In its submission to the European Commission’s public consulta-

tion on the draft guidelines on environmental and energy State

aid, Eurelectric emphasised the role capacity mechanisms can

63Excerpt from [EC, 2013]

64[General Commission for Strategy and Foresight, (CGSP), 2014]

40

play in meeting the challenges posed by the energy transition,

notably the need to accommodate a high level of renewable

generation on the power system:

The implicit assumption of the guidelines is that ensu-

ring a competitive, sustainable and secure energy system

can be achieved primarily through an energy-only market

model. EURELECTRIC considers that with moving towards

a low-carbon energy system with a high level of variable

renewables penetration, a fully-fledged investigation into

the need for developing a new market design will be crucial

to tackle the current challenges within the electricity sys-

tems related to generation adequacy and security of sup-

ply. The need for reviewing the market design has already

been recognised in some member states facing growing

generation adequacy problems in view of high level of RES

penetration and some cases, higher peak demand. There

is growing evidence that in some regions move towards

a market design based on markets for both energy and

capacity might be needed.

A capacity mechanism can thus be an efficient tool for driving

the energy transition in that it guarantees the same rewards for

the contributions of generation and demand response capaci-

ties, and for those of existing and new capacities.

The justifications for choosing a market-wide capacity mecha-

nism for France are outlined in chapter 2 of this report.

Suffice it to say here that this type of mechanism sends eco-

nomic signals to all market stakeholders and avoids locking in

economically inefficient generation plants that make no contri-

bution to security of supply.

In this sense, the proposed capacity mechanism should limit

unnecessary investments in new generation capacities and

guarantee the fair remuneration of existing assets.

1.4.4.3 Taking into account the physical needs of the

power system

For a mechanism to generate signals that are proportionate to

security of supply and energy transition objectives, it must cor-

respond exactly to what the energy system needs physically to

ensure security of supply. It must guarantee that sufficient quan-

tities of the different characteristics required in a given situation

are present in sufficient quantity: capacity, flexibility,

etc. ENTSO-E, the European Network of Transmis-

sion System Operators, also promotes this idea65:

PRINCIPLE 1: SHIFTING THE FOCUS TO THE PHYSICAL

NEEDS OF THE SYSTEM

For ENTSO-E, the decision to implement CRM in addition to

electricity markets should be preceded by a careful assess-

ment of the physical needs of the system. In particular, with

the advent of significant variable renewable generation, secu-

rity of supply consists of diverse challenges: long term ade-

quacy, flexibility, voltage control, transient stability, etc. Those

issues are much more complex and require thorough tech-

nical analysis. It is only on the basis of such a diagnosis that

possible solutions can be assessed.

Only TSOs, in-conjunction with national regulators, can pre-

cisely forecast the nature of those future security challenges.

European TSOs must therefore be part of all up coming

debates concerning CRMs and market design.

RTE applied these principles in all of its proposals and recom-

mendations throughout the consultation on the French capa-

city mechanism. Its positions on the capacity mechanism

are underpinned by a conviction that market design must be

shaped to serve consumers while reflecting the operational

constraints and physical needs of the system. This focus on

building a market based on the real value of products traded,

rather than the specific demands of some stakeholders,

extends beyond the capacity mechanism: it is a general prin-

ciple of market design.

The French capacity mechanism is designed to meet the security of supply targets set by public authorities. In France’s case, this means com-pensating all capacity and measures that help preserve the supply-demand balance during peak periods, without guaranteeing remuneration irres-pective of security of supply needs.

The mechanism must be strictly proportional to security of supply considerations. These consi-derations may evolve over time, for instance if the challenges raised by some renewable energy sources become more significant. The proposals made by RTE based on the consultation integrate the fundamental building blocks to enable such changes.

65[ENTSO-E, 2012]

41

WHY A CAPACITY MECHANISM IS NECESSARY / 1

Capacity market

Capacity market

Capacity payment (since 2007)

Capacity payment(since 1998)

Capacity payment (since 2011 –

currently suspended)

Strategic reserve

Strategic reserve

Strategic reserve(phase-out 2020)

Capacity payment(capacity marketplanned for 2014)

Capacity payment(since 2006)

Figure 8 – Map of capacity mechanisms in Europe (2013)(Source: ACER)

 No capacity mechanism

  Capacity mechanism proposed/under consideration

  Capacity mechanism operational

1.5 Capacity mechanisms in Europe

France’s decision to create a capacity mechanism to ensure that

the security of supply criterion is met is not an isolated initiative.

The number of European countries that have introduced or are

planning capacity mechanisms is growing, reflecting the possi-

bilities offered by Directive 2005/89/EC66. In some countries,

the decision was taken long ago (Spain, Sweden, Finland, Ireland

and, to a lesser degree, Italy). Others (United Kingdom) have

already made considerable progress in their plans,

and should be organising their first capacity auc-

tions in 2014. The idea is still being considered in

some Member States, and decisions could be made

within the coming months. The map below, crea-

ted by ACER67, offers an overview of the capacity

mechanism situation across Europe.

The additional information RTE gathered for the purposes of

its own studies or collected via ENTSO-E shows that even more

countries have or plan to implement capacity mechanisms. For

instance, it appears that Bulgaria has a capacity remuneration

mechanism in place, and also uses one-off tenders68. There is

also evidence to suggest that capacity mechanisms are being

weighed in countries not included in this category on the ACER

map, Poland being a case in point69.

These examples show the degree to which capacity mecha-

nisms have become a reality in Europe. With this in mind, the

potential impact of the creation of a capacity mechanism in

France must be put into perspective, as two neighbouring

countries (Italy and Spain) have had mechanisms in place for

some time, and two others (the United Kingdom and Belgium)

are creating their own mechanisms.

Moreover, capacity is not remunerated under the exact same

terms in all countries, even in the absence of a clearly identi-

fied capacity mechanism. The reserves used by transmission

system operators in Europe vary greatly from one country to

the next, as do their remuneration procedures. For instance,

Germany does not have a capacity mechanism for now, though

one is under consideration70. However, the operating reserve

volumes German system operators have under contract are

almost twice as high as in France71. There are other forms of

reserves as well, such as Reserve Power Plants (ResKV), a type

of strategic reserve used to relieve congestion on the grid in

66Directive 2005/89/EC of 18/01/2006 concerning measures to safeguard security of electricity supply and infrastructure investment.

67[ACER, 2013]

68The prices of electric power sold by producers (…) may include the components: a capacity charge and a commodity charge. [SEWRC, 2004]. [BG, 2011]

69The work on introducing a law for a capacity mechanism, which guarantees producers a price for generating backup electricity, may start in the first quarter [of 2014], Marek Woszczyk, the head of Urzad Regulacji Energetyki, said in Warsaw. Bloomberg, 07/10/2013.

70See, for example, [BDEW, 2013]

71Discrepancies in reserve volumes between the countries reflect structural differences in market architectures and reserve usage.

42

exchange for capacity remuneration. The new government in

place in Germany since November 2013 is weighing the issue,

and many proposals have been submitted. One came from

BDEW (Bundesverband der Energie und Wasserwirtschaft72,

the German association of energy and water industries), which

is suggesting a decentralised and voluntary market-wide

capacity mechanism. BDEW’s proposal is one of a handful of

options the German government is considering implementing

at the federal level.

The bottom line is that capacity mechanisms have become a

reality in the European energy landscape. Chapter 9 of this

report discusses the interconnection of the French capacity

mechanism with the systems implemented in neighbouring

Member States.

1.6 Conclusions

The introduction of a capacity mechanism will profoundly

change the design of the electricity market and address the

shortcomings of its current organisation. The goal is to ensure

that investments are made in capacities that can be dispatched

during periods of peak demand and, more generally, in keeping

with energy transition objectives, to reward investments that

provide benefits to the power system proportionately to the

benefits provided to society.

In its current form, the European electricity market is based on

the theoretical model of the energy-only market with provisions

allowing stakeholders to trade energy in a market characterised

by free and undistorted competition. The energy-only market

ensures that generation capacity dispatched is remunerated at

the marginal production cost of the mix. Prices formed on this

basis generate only one economic signal, which is considered

sufficient to optimise generation schedules in the short term

and determine the optimal size of the mix for the long term,

including during shortage situations. Within this theoretical

framework, security of supply is supposed to be guaranteed by

the market, thanks to an economic signal that assigns a value

to capacity.

However, the academic literature identifies imper-

fections that can be empirically observed in today’s

energy markets.72[BDEW, 2013]

Many Member States already have or are introdu-cing capacity mechanisms to address existing or potential threats to security of supply. France's initiative is thus not unique: on the contrary, it is part of a broader trend to reform the architecture of electricity markets in Europe. 

Because Member States have different reasons for implementing capacity mechanisms, the mecha-nisms they create reflect specific national charac-teristics and are not all alike. One challenge when such mechanisms are being introduced in Europe is to ensure that they are compatible with the internal electricity market nearing completion. Coordina-tion between neighbouring Member States should thus be sought. Just as it is taking an active part in preparing the ENTSO-E Network Code and regional initiatives overseen by regulators, RTE will make every effort to help find solutions that make capacity mechanisms compatible with the internal market.

First, the hypotheses used in the theoretical analysis of energy-

only markets are not realistic in terms of the expected behaviour

of participants or the operating constraints created by the gene-

ration and circulation properties of electricity.

Second, security of supply is a public good and is not automa-

tically guaranteed by the market due to externalities: it benefits

all once it has been produced, but when this is not the case all

network users are affected, regardless of the value they place on

it. This reduces investment incentives as it is not in the interest

of market stakeholders to invest in some capacities that would

benefit security of supply, since the profits they would generate

are lower than the benefit for society.

Lastly, a theoretical analysis of the energy-only market suggests

that a long-term equilibrium will be achieved based on a static

approach. This equilibrium is rarely achieved with a more realis-

tic dynamic approach. Cycles of investment in power capacity

are characterised by a sort of viscosity when it comes to adding

or retiring generation facilities. As these cycles alternate, succes-

sive waves of overcapacity and under-capacity are observed, at

the expense of security of supply and the system’s economic

efficiency. A detailed look at the theoretical framework of the

energy-only market raises questions about the market’s ability

to effectively guarantee security of supply. This conclusion is

also supported by a factual analysis of the situation.

43

WHY A CAPACITY MECHANISM IS NECESSARY / 1

If the imperfections of the energy market are to be addressed

and the requirements of the energy transition and security of

supply met, a tool must be available to effectively encourage

investment and complement the signals generated by existing

mechanisms. It is with this in mind that France is currently imple-

menting a series of market instruments. These instruments are

intended to improve how electricity markets function, without

being considered substitutes for one another. It is therefore

crucial that they be coordinated. Key undertakings include ena-

bling the integration of electricity markets over all timescales,

developing interconnections, allowing demand and demand

response to participate in markets, overhauling renewable sup-

port mechanisms and implementing a capacity mechanism.

Taken as a whole, these efforts aim to make the existing energy

market more efficient and add the dimensions that are lacking. In

this regard, a market mechanism focusing on security of supply

must reward the contributions of generation and demand res-

ponse capacities to security of supply, i.e. the contributions these

capacities make when the equilibrium of the power system is at

risk. The mechanism is not designed to provide additional reve-

nue to generators or demand-side operators irrespective of real

security of supply needs. In specifically seeking to address the

challenge posed by peak demand, the French mechanism will

have to make every effort to integrate demand response, which

can be an efficient way to ensure the system has all the capacity

it needs. The creation of a capacity mechanism is thus perfectly

compatible with the policy of encouraging demand response.

Many Member States have introduced this type of mechanism.

France’s initiative is in keeping with this trend. However, analysis

of these mechanisms reveals that they are very heterogeneous

and incorporate the full spectrum of possible solutions in terms

of market design.

The next chapter focuses on the different options available

when implementing capacity mechanisms and the specific

choices made by public authorities in France.

France already has the instruments required to measure secu-

rity of supply. They can be used to conduct assessments before

implementing public policies to correct shortcomings. These

include adequacy assessments like those found in RTE’s Ade-

quacy Forecast Reports. Such assessments have revealed the

existence of a peak demand phenomenon in the French power

system, and the fact that peak demand is growing faster than

electricity demand as a whole. They have also shown that safety

margins are gradually decreasing and will be eliminated in 2017.

Security of supply must therefore be carefully monitored in

France.

These considerations must be weighed against the difficulties

many generators and demand-side operators are having in

earning adequate remuneration. At a time when the econo-

mic fundamentals of the sector are changing considerably, the

energy-only market can no longer drive investment efficiently.

The existence of economic cycles is also corroborated by recent

trends in the generation mix.

Looking beyond the failures observed in energy markets, the

physical needs of the European and French power systems are

also changing dramatically, and this could exacerbate market

failures. If the ambitious objectives set by the European Union

for the energy transition are to be met, the power system will

have to play a greater role: it will need to adapt and accommo-

date a huge and growing quantity of renewable energies. This

makes it all the more necessary to have flexible capacities, whe-

ther supply- or demand-side resources, to guarantee that elec-

tricity supply and demand will be balanced.

An analysis of these trajectories leads to two observations: first,

significant investment will have to be made in the power sec-

tor, bearing in mind that the peak demand phenomenon could

continue due to the increasing role public authorities want elec-

tricity to play to help meet their energy policy objectives, and

second, increasing renewable penetration could result in a need

for even more flexibility.

44

When failures have been identified in a market

providing a public good, public authorities are jus-

tified in taking measures to correct them75. This

public intervention can take the form of regulatory

measures76 or economic instruments that lead

2.1 Why a quantity-based market mechanism

The architecture for the French capacity mechanism was defi-

ned in several stages: the general principles were laid out in the

NOME Act of December 2010, after which the overall organi-

sation of the mechanism was set forth in the implementation

decree of December 2012, drawing in part from

the recommendations in RTE’s report to the Energy

Minister of October of 201174.

2. CHOOSING THE RIGHT CAPACITY MECHANISM FOR FRANCE

In adopting a capacity mechanism to ensure security of sup-

ply, public authorities can choose between different market

designs, and their decisions are shaped in large part by the

country’s specific context. The Agency for the Cooperation

of Energy Regulators (ACER) proposed a classification of the

different types of public intervention possible in its report on

capacity mechanisms and the internal market73. The options

considered for the French capacity mechanism are repre-

sented in the taxonomy below:

73[ACER, 2013]

74[RTE, 2011]

75See Chapter 1 of this report.

76Pollution standards are an example.

77Intermediate forms also exist, for instance a quantity target with a price condition.

Figure 9 – Taxonomy of capacity mechanisms

The capacity mechanism that emerged from this process is

adapted to France’s situation and the specific challenges it is

intended to address. The design corresponds to a mechanism

that is market- and quantity-based, market-wide (applying to

all capacity) and decentralised. These three defining characte-

ristics are discussed in sections 2.1, 2.2 and 2.3 of this chapter,

respectively.

economic actors to change their behaviour. Other than in the

case of regulatory measures (the thermal regulation of 2012,

energy labelling, new energy standards), public intervention

involves introducing one of two types of economic instrument:

price-based regulations or quantity-based regulations77. Public

Price-basedQuantity-based

One-off tenders

Strategic reserve

Capacity obligation

Decentralised

Capacity auction

Centralised

Capacity mechanism

Capacity payment

Targeted mechanism Market-wide mechanism

45

CHOOSING THE RIGHT CAPACITY MECHANISM FOR FRANCE / 2

intervention is managed differently with these two options.

Price-based regulation involves using instruments to set a

price, but volumes then depend on private decisions. With

quantity-based regulations, instruments are used to define

quantities but prices are determined by the market (market-

based approach). Academic literature abounds with analyses

of this aspect of public intervention.

Many examples exist of choices that have been made between

price- and quantity-based regulation in the energy sector,

and more specifically within the context of the energy tran-

sition. Renewable support policies have been widely exami-

ned: some countries opted for price-based regulation in the

form of guaranteed purchase prices, while others introduced

quantity-based instruments such as RES quotas in the United

States [Renewable Portfolio Standard]. The CO2 emissions

trading scheme is another recent example of quantity-based

regulation.

This distinction between price- and quantity-based regulations

is equally important when it comes to security of supply. Price-

based regulation is already used through capacity payments78.

And capacity markets are a form of quantity-based regulation.

As such, the first choice that had to be made in designing the

French capacity mechanism was between price- and quan-

tity-based regulation.

During the consultation of 2011, several market stakeholders

expressed a preference for capacity payments, citing this

type of mechanism’s benefits in terms of simplicity and secu-

rity for investors. They also noted that capacity payments

were used in other European Union Member States (Spain,

Italy, Ireland, etc.).

Price-based mechanisms nonetheless present several draw-

backs that have been described in theoretical terms79, and the

practical consequences of which were beginning to become

visible in Europe at the time. Difficulties in determining an

appropriate guaranteed purchase price for some types of

renewable energy led to erratic development trends, inclu-

ding a surge of investments in photovoltaic power in France

late in 2010. Demand was also declining during this period,

underscoring the possibility that capacity payment mecha-

nisms could subsidise overcapacity providing no value to

consumers.

The fact is that price-based mechanisms offer few levers on

the service provided since everything depends on how well

authorities determine the purchase price, often

working with an asymmetry of information. As ACER

notes:

It is difficult to determine the right payment level

and to determine the effect of the payments;

the mechanism provides no guarantee against

extreme spikes. This is probably why Capacity

Payments are often combined with price caps in

the wholesale markets in order to avoid extreme

prices. An important drawback is that Capacity

Payments are not well targeted; it is not clear

what consumers pay for and what they get in

return80.

It was due to these considerations that the capa-

city payment solution was ruled out, and French

lawmakers opted to implement a mechanism

based on quantities and a market price. This deci-

sion was consistent with the recommendations of

the Poignant-Sido report:

Proposal 16: Plan the introduction of a capacity market in

France81.

This preference for a quantity-based mechanism over a capacity

payment scheme has since been supported in the European

Commission guidelines, which expressed serious concerns

about the use of capacity payments:

Establishing the correct value for capacity payments is

difficult and open to accusations of political interference.

Neither can it be assured that required capacity will be

delivered (particularly given regulatory uncertainty asso-

ciated with the setting of the payment) or alternatively that

excess capacity will not result from the scheme resulting in

overcompensation.

[…]

Mechanisms based on capacity payments do not ensure that

the identified adequacy gap is filled and create significant

risks of overcompensation.

Recent trends in Europe make the decision to implement a

market mechanism in France seem all the more relevant: for

instance, Italy and Spain are both moving away from capacity

payments and towards a quantity-based mechanism.

78A capacity payment is a fixed price paid to a class of economic agents for capacity that is available. ACER uses the following definition: “Capacity Payments represent a fixed price paid to generators/consumers for available capacity. The amount is determined by an independent body. The quantity supplied is then independently determined by the actions of market participants.”

79[Weitzman, 1974] “Quantities are better signals for situations demanding a high degree of coordination.”

80[ACER, 2013]

81[Poignant-Sido, 2010]

46

Once the decision in favour of quantity-based regulation was

confirmed, a choice had to be made about the scope of the

mechanism. Indeed, capacity mechanisms differ depending on

whether all or only part of generation and demand response

capacities are eligible to participate. This was one of the key

criteria ACER used to classify capacity mechanisms in its taxo-

nomy82: it drew a distinction between targeted mechanisms and

market-wide mechanisms (applying to all capacity).

Targeted mechanisms apply to a specific and limited amount

of generation capacity. The two main types of targeted mecha-

nisms are strategic reserves and one-off tenders. With strate-

gic reserves, capacities are “set aside” and dispatched only in

situations where load curtailment would otherwise be required

(§ 2.2.2.2). One-off tenders offer a solution for situations where

capacity shortages appear possible (§ 2.2.2.3). Market-wide

mechanisms apply to all supply- and demand-side capacities

that already exist or are planned (new capacities).

In the Staff Working Document on adequacy accompanying

its Communication of 5 November 2013 on State intervention

in electricity markets83, the European Commission seems to

lean in favour of targeted capacity mechanisms. It is therefore

important to consider this option, especially as, since markets

were deregulated, the legal framework in France has allowed

the State to react to perceived threats to security of supply by

organising targeted auctions, as part of the Multi-Year Invest-

ment Plan (programmation pluriannuelle des investissements)

instituted by the law of 10 February 2000.

The appropriate scope for the French capacity mechanism was

further discussed in 2011 based on the provisions of the NOME

Act, which anticipated a market-wide capacity mechanism. In

the conclusions of its report published in 2011, RTE supported

the inclusion of all capacities in the mechanism84:

For the mechanism to provide a real guarantee

in terms of security of supply, it is crucial that all

capacities participate in it and that suppliers make

availability commitments for all of their capacities.

If some capacities are excluded, then the scheme

would not deliver much more than is currently

possible, and this could create legitimate concerns

about the need for the mechanism. A mechanism

that only covered new capacities would have

82[ACER, 2013]

83[EC, 2013a]

84[RTE, 2011]

2.2 Why a market-wide capacity mechanism

much the same effect as the tenders already allowed

through the Multi-Year Investment Plan.

Public authorities took this recommendation into account and

adopted it in Decree 2012-1405 of 14 December 2012:

All capacity suppliers, or persons mandated by them, are to

present, for each delivery year, a certification request for their

capacities before a deadline set based on the technical cha-

racteristics of the capacities or, for new capacities, the status

of the project.

The choice to implement a market-wide mechanism was made

based on five key objectives: provide real guarantees in terms

of security of supply (§ 2.2.1), address market imperfections

and avoid distortion (§ 2.2.2), minimise the cost to consumers

(§  2.2.3), ensure the mechanism’s economic efficiency in the

presence of investment cycles (§ 2.2.4) and adopt a mechanism

that reflects France’s specific situation (§ 2.2.5).

2.2.1 Provide guarantees in terms of security of supply

The main reason for adopting a market-wide mechanism is that

availability commitments must be secured for all capacities to

guarantee that security of supply is truly enhanced for consu-

mers. This is because security of supply is a public good that

cannot be ensured by specific capacities individually.

When electricity supply is tight, all capacities contribute to mee-

ting all demand, and there is no reason why only some should

be rewarded. On the contrary, because it is impossible to identify

the power plants that contribute specifically to security of sup-

ply, there is no technical justification for a mechanism that does

not reward all capacities.

The approach taken with the French capacity mechanism  –

equal consideration is given to the contributions of all capa-

cities to security of supply, taking into account their specific

characteristics and availability commitments – thus provides

the best guarantee to consumers in terms of security of

supply.

47

CHOOSINGTHERIGHTCAPACITYMECHANISMFORFRANCE / 2

2.2.2 Address market imperfections and avoid distortion

To enhance security of supply, a capacity mechanism must

address the energy market imperfections discussed in chapter 1.

Not all mechanisms have the same economic impact, making it

important to identify those that can correct these imperfections

without creating distortions. Below is an analysis of market-wide

capacity mechanisms, strategic reserve schemes and one-off ten-

dering procedures.

2.2.2.1 Economic impact of market-wide capacity

mechanisms

Market-wide capacity mechanisms involve systematically rewar-

ding all contributions to security of supply, though the reward

may be equal to zero. The mechanisms function all the time,

and when demand representing total capacity needs is mat-

ched against supply representing all capacities, it creates a mar-

ket price that refl ects the scarcity of the resource. This type of

mechanism can be implemented within the diff erent types of

architecture discussed in § 2.3.

Market-wide capacity mechanisms create opportunities

to earn additional revenue for all capacities, based on their

contribution to security of supply. This revenue is added to

the inframarginal rent operators earn on the energy market

and makes up for the missing money resulting from imperfec-

tions in the energy market. The figure below shows how the

mechanism functions85 using the example from

chapter 1.

It can be noted that the capacity mechanism cre-

ates the same price duration curve as the perfect

energy-only market except during load curtailment.

A market-wide mechanism associated with a mar-

ket price can, if well designed, address the imperfections of the

energy market without distorting prices.

2.2.2.2 Economic impact of a strategic reserve

mechanism

2.2.2.2.1  Defi nition of a strategic reserve 

Strategic reserve mechanisms involve pulling some capacities

out of the electricity market and “reserving” them to be dispat-

ched only in situations where load curtailment would otherwise

be required. In such extreme situations, the energy generated

by reserved capacities is sold on the energy market at a prede-

fi ned dispatch price, usually corresponding to the price cap on

the energy market.

ACER uses the following defi nition86:

Strategic Reserve

In a Strategic Reserve scheme, some generation capa-

city is set aside to ensure security of supply in exceptio-

nal circumstances, which can be signaled by prices in

85A price cap is applied to represent the market's imperfections (see section 2.2.2).

86[ACER, 2013]

Peak VC

VoLL

Peak VC

VoLL

Price cap Price cap

Missing money, decline in inframarginal rent due to price decrease during load shedding

No additional load shedding, price duration curve maintained. Insufficient rent on the energy market, offset by capacity price applied to all capacities

Missing money problem: Price decrease during load shedding

No additional load shedding, peak capacity maintained

Merit order Price duration curve

Quantity (GW)

Price (€/MWh)

Hours of operation

Price(€/MWh)Optimal load shedding

Peak capacity Optimal load shedding

Functioning, optimal case

Inframarginal rent, optimal case

Functioning with market mechanism applying to all capacities

Inframarginal rent with market mechanism applying to all capacities

Figure 10 – Illustration of the merit order and price duration curve for a market-wide capacity mechanism versus a perfect energy-only market

48

the day-ahead, intra-day or balancing markets

increasing above a certain threshold level. An

independent body, for example the Transmission

System Operator (“TSO”), determines the amount

of capacity to be set aside to achieve the desired

degree of adequacy and dispatches it whenever

due. The capacity to be set-aside is procured and

the payments to this capacity determined through

a (typically year-ahead) tender and the costs are

borne by the network users.

In other words, this is a targeted capacity remunera-

tion tool designed to guarantee adequacy in volume

terms, i.e. that load curtailment levels are optimal.

However, for a long-term equilibrium to be achie-

ved, the mechanism must not only restore the opti-

mal level of load curtailment by securing a certain

quantity of reserves, but also allow the capacity that

remains in the market to cover its fixed costs and thus make up

for the missing money.

A strategic reserve mechanism can thus only function pro-

perly under the strict condition that it has enough influence

over energy prices to correct the missing money problem. An

example of the effects a perfectly designed strategic reserve

mechanism would produce is presented in figure 11 below.

It should be noted that the price duration curve under the well-

designed strategic reserve mechanism is identical to the one in

the market at equilibrium with missing money in § 1.1.3.1. On

the other hand, the energy price is higher when reserves are dis-

patched than in the perfect energy-only market.

The missing money for capacities still in the market (not set

aside under the strategic reserve mechanism) is offset in theory

by prices being maintained at the price cap while reserved capa-

city is in use. Inframarginal rents thus cover fixed costs. Incen-

tives to invest or remain in the market are the same as in the

perfect energy-only market87.

For capacities included in the strategic reserve, revenue earned

on the energy market88 is complemented by a fixed component,

typically funded by a tariff surcharge paid by final consumers

(e.g. found on their bills, in addition to charges for energy). This

surcharge is usually fairly low in relation to MWh consumed,

since it is only intended to cover the share of fixed costs borne

by reserved capacity not covered by revenue earned in the

energy market.

2.2.2.2.2  Assessment of the impact of a strategic 

reserve mechanism 

Strategic reserve mechanisms, especially their parameters and

characteristics, must be perfectly defined to correct market

imperfections and resolve the missing money problem. In par-

ticular, the key parameters used for defining reserves and the

situations in which they are dispatched (reserve quantities, dis-

patch conditions, dispatch price or price offered for reserves on

the market) have a major influence on the mechanism’s ability

to restore balance.

The goal in setting these parameters must be to correct market

imperfections, not to minimise costs to consumers. For instance,

if the missing money problem is not resolved, capacity will conti-

nue to be withdrawn from the market and the strategic reserve

alone will not be able to guarantee security of supply over the

long term, except if it gradually absorbs all capacities in the mar-

ket. This would create what the academic literature refers to as

a slippery slope89.

This analysis suggests that three conditions must be met for a

strategic reserve mechanism to be able to resolve the missing

money problem for all capacities and keep load curtailment at

the optimal level:

> Required reserve volumes must be calculated based

on the optimal energy mix and desired level of load

shedding;

> Dispatching and remuneration procedures must ensure the

remuneration of strategic reserves while also preserving

investment incentives in the energy-only market;

> The mechanism and operator overseeing it must be cre-

dible for the mechanism to function properly and interact

with the energy-only market, which becomes all-impor-

tant when moving from a theoretical framework to the real

market.

Empirical observation shows that these mechanisms are often

implemented to avoid retiring old and polluting power plants90.

In addition to potentially jeopardising the environmental targets

of Europe’s energy policy, this underscores how tricky it can be to

find a virtuous system for selecting capacities for inclusion in the

strategic reserve. It also raises concerns about the terms under

which unprofitable, private assets are procured by public enti-

ties: Are they taken over temporarily, and allowed to return to the

market once economic conditions so permit (in which case the

mechanism would serve to protect operators from price risks)?

If they are taken over permanently, issues could arise when the

capacities are new and have a lifespan of several decades.

87In this case, price signals in the energy market with a strategic reserve mechanism in place are similar to those seen in an energy-only system when capacity is too low and shortfalls too high.

88Strategic reserves are remunerated in the energy market in a rather specific way, since the reserves are always dispatched at a predefined price, usually corresponding to the energy price cap. The remuneration thus always represents an inframarginal rent reflecting the differential between the variable cost of the strategic reserves and the price cap.

49

CHOOSINGTHERIGHTCAPACITYMECHANISMFORFRANCE / 2

The European Commission also lists a series of precautions to

be taken in designing strategic reserve mechanisms91:

[It] is important that [Strategic Reserves] be properly imple-

mented. Union rules on public procurement must be res-

pected and help ensure that there is no overcompensation.

Where strategic reserves are used to keep prices low, this

may result in high emissions from ineffi cient old plants and

discourage the development and deployment of new and

more effi cient technologies, including storage and demand

side response. With market coupling and the introduction of

cross-border intraday trading such a failure would happen

within a common price mechanism and spill over across

borders. It is therefore not only not cost-eff ective but risks

seriously distorting the internal market. This problem can

be avoided when strategic reserves are clearly used only in

the event of the failure of the (short run) wholesale market

to match supply and demand. This requires objective and

transparent criteria as to when strategic reserves can be

deployed.

A well-designed strategic reserve mechanism can correct mar-

ket imperfections. The functioning of this type of mechanism

nonetheless distorts energy prices, since off setting the mis-

sing money results in more frequent price spikes in the energy

market.

2.2.2.3 Economic impact of a capacity

auction mechanism

2.2.2.3.1  Defi nition of capacity auction 

schemes 

Capacity auctions are a class of capacity mecha-

nism under which total capacity needs are determi-

ned several years in advance and auctions are orga-

nised if additional capacity is needed. The European

Commission refers to this type of scheme as tende-

ring procedures92. The mechanism does not apply

to all capacities93 and tenders are only organised

occasionally94.

2.2.2.3.2  Assessment of a capacity auction 

mechanism 

One-off capacity auctions can off er public autho-

rities a practical way to intervene quickly to safe-

guard security of supply. In the European Commis-

sion’s words:

A tendering procedure has the advantage

of being relatively easy to organise and will

ensure that investors actually construct the

capacity tendered, and then participate in

the market as normal. New capacity which

89[Finon & Roques, 2013]. See [Stoft, 2002] and [De Vries, 2004] on the theoretical functioning of strategic reserves.

90“Old units can be purchased and kept available.” [De Vries, 2004]“[strategic reserve] provides for keeping old units operational, because they can be sold or leased to the system operator.” [De Vries, 2007]“The TSO can take over old units that the owners have decided to close.” [Finon & Pignon, 2008]

91[EC, 2013]

92[EC, 2013a]

93“Tendering procedure is normally less distortionary and easier to implement than market wide capacity mechanisms.” [EC, 2013a]

94“Properly implemented, tendering constitutes a one off intervention on the market.” [EC, 2013a]

Peak VC

VoLL

Peak VC

VoLL

Price cap Price cap

Missing money, decline in inframarginal rent due to price decrease during load shedding

Inframarginal rent restored through decrease in installed peak capacity/strategic reserve deployed at price cap

Missing money problem: Price decrease during load shedding

Decrease in installed peak capacity – strategic reserve deployed at price cap

Merit order Price duration curve

Reserves

Quantity (GW)

Price (€/MWh)

Price (€/MWh)

Hours of operation

Optimal load shedding

Peak capacity Optimal load shedding

Functioning, optimal case

Inframarginal rent, optimal case

Functioning with strategic reserve

Inframarginal rent with strategic reserve

Figure 11 – Illustration of the merit order and price duration curve under a perfectly designed strategic reserve mechanism versus a perfect energy-only market

50

benefits from the tender continues to participate on the

market. Consequently, it is important that the tender not

be designed in such a way as to distort normal market ope-

ration or production decisions or to distort future invest-

ment decisions95.

Special tendering procedures are thus fundamentally desig-

ned to resolve temporary and clearly identified physical issues.

France already has a similar instrument through its Multi-Year

Investment Plan. It allows public authorities to translate their

energy policy objectives through actions targeting the energy

mix. The existence of this instrument is not being called into

question with the implementation of the capacity mechanism.

Tendering procedures are fall-back measures and thus not

an appropriate solution to the structural imperfections of the

market.

Firstly, they do not structurally modify the economics of elec-

tricity markets, and do not place a specific value on security of

supply. And the missing money problem revealed by econo-

mic theory affects all capacities in the same way96. Therefore,

in an imperfect market where a missing money phenomenon

reduces investment incentives, the creation of new capacities

subsidised by a special tendering procedure would only add to

the profitability problem for all capacities.

Secondly, all capacities contribute to security of supply from a

technical standpoint. The only valid justification for a targeted

capacity mechanism would thus have to be economic, for ins-

tance a missing money problem that is particularly significant

for some plants. In this case the mechanism would be a sort of

specific subsidy granted to certain capacities simply because

they are not profitable. This would run totally counter to the

philosophy of an integrated energy market in which investors

assume the risk associated with their investments and make

decisions about investing in or retiring capacities based on their

revenue forecasts.

A mechanism that only targets some capacities necessarily

creates distortion. This is particularly visible with

selective mechanisms targeting new capacities. In

situations where there are facilities in the market

that are operational and have in some cases only

been in service for a few years but could be retired,

introducing a mechanism that subsidises new capa-

cities exclusively would not seem to make economic

sense and could cause considerable distortion.

The Commission addresses this concern about preventing

distortion when selecting capacities eligible to participate in

mechanisms in its recommendations on the neutrality of capa-

city mechanisms between existing and new capacities97:

In certain situations, it can be more cost-effective to retrofit

or retain existing generation capacity, which would other-

wise shut down, to keep it operational. This can also help

potentially to avoid the lock-in effects of constructing new

(fossil fuel) generation capacity.

Therefore, capacity mechanisms open to capacity retention

as well as new investments, without discrimination between

the two categories ensure cost-effectiveness and minimise

distortion.

The approach adopted by public authorities in France aims spe-

cifically to avoid distortion by giving equal consideration to all

capacities, be they new, older or refurbished.

Lastly, it should be noted that if special tenders are organised

too frequently, investors could begin to wait for the tenders,

which would be counterproductive:

[T]here is still a risk of distorting investment signals

by encouraging a ‘wait for the tender to be launched’

approach on the part of investors to secure additional

revenue. In the context of the current transition of the

electricity system, and in some Member States, the deci-

sion to shut down nuclear capacity, well designed and

one off tenders could have a role to play. However, only

if the connection between the tender requirements and

the system transition is clear, is it likely that investors

would consider a commitment not to repeatedly launch

more tenders, in order to be credible. Where a tender is

implemented to correct for regulatory failures it is likely to

undermine confidence in the willingness of public bodies

to correct such failures, thereby exacerbating the under-

lying problems98.

Because the tenders would be organised only occasionally and

closely administered, this scheme will automatically be less

effective in supporting the energy transition. Relying on this

type of mechanism to drive changes in the energy mix would

be tantamount to admitting the failure of the role of markets

for investments, and would transfer investment risk from private

companies to consumers.

95[EC, 2013a]

96See section 2.1.2 of this report

97[EC, 2013a]

98[EC, 2013a]

51

CHOOSING THE RIGHT CAPACITY MECHANISM FOR FRANCE / 2

2.2.3 Minimise the cost to consumers

Targeted capacity mechanisms are often presented as a way to

minimise the cost to consumers, since only a limited quantity

of capacity is rewarded99. The European Commission mentions

this characteristic100:

One particular concern about market wide capacity mecha-

nisms is that they can over reward generation which was

already financially viable.

However, an analysis of strategic reserves in operation shows

that they do not cost consumers less than market-wide capa-

city mechanisms. This issue of cost was a key consideration in

the design of the French capacity mechanism, which includes a

number of provisions to ensure that the cost of the mechanism

is strictly proportional to its objectives.

2.2.3.1 Comparison of costs entailed by strategic

reserves and market-wide capacity mechanisms

On first analysis, it may seem logical that a market-wide capacity

mechanism should cost final consumers more than a strate-

gic reserve, since it covers more capacity. With the former, the

cost of capacity for final consumers represents rewards for the

contributions of all capacities to security of supply, while with

the latter the tariff surcharge only aims to complement the infra-

marginal rent for the capacities reserved.

This logic is not borne out by a careful analysis of the mecha-

nisms’ financial impact on different market stakeholders. In fact,

this analysis shows that, with two perfectly designed mecha-

nisms that exactly offset the missing money resulting from

energy market imperfections, strategic reserves do not cost final

consumers less than market-wide capacity mechanisms.

A strategic reserve mechanism that is consistent with economic

theory is based on a system in which generators are compensa-

ted in two ways for missing money:

> For capacities included in the strategic reserve, fixed costs are

covered through two remuneration systems:

• In the energy market, capacities earn a specific rent every time

they are dispatched. This rent corresponds to the difference

between the dispatch price for reserves and their variable cost;

• This rent is then complemented by a fixed remuneration of

the capacities reserved, which is financed by final consumers;

> For capacity that remains in the market, revenue increases since

the price cap is reached more often on the energy market.

Electricity users are therefore called upon to offset the missing

money at two levels. They pay a tariff surcharge to complement

the revenue earned by reserved capacities. In the meantime,

prices in the energy market reach the price cap more often than

in the energy-only market, not only during load curtailment but

also when the reserves are dispatched. In other words, strate-

gic reserves result in direct costs, through the remuneration of

capacities reserved, as well as an indirect cost reflected in more

frequent price spikes in the energy market.

With a market-wide capacity mechanism, the mis-

sing money resulting from market imperfections

is offset exclusively through the capacity price paid

by final consumers. Unlike with strategic reserves,

consumers benefit from a lower and more stable

energy price, equal to the market price in a perfect

energy-only market101. They nonetheless participate

in a more direct way, through the capacity price,

which is supposed to offset the missing money in full,

whereas the strategic reserve only offsets part of it.

Figure 12 compares the economic results of capa-

city in three situations: the original situation, with

missing money that is not offset; and situations

where adjustments are made through a market-

wide mechanism or a well-designed strategic

99Targeted capacity mechanisms can nonetheless entail hidden costs, for instance in energy prices, making it difficult to evaluate them based solely on face value cost.

100[EC, 2013a]

101Except during load shedding, if we assume that the market imperfection that led to the implementation of the capacity obligation is representative of a price cap below the cost of unserved energy.

Assessments of the economic impact of different classes of capacity mechanism lead to the fol-lowing conclusions

> Market-wide capacity mechanisms address mar-ket imperfections without distorting energy prices;

> Targeted mechanisms such as strategic reserves address market imperfections but distort energy prices;

> Targeted mechanisms such as one-off tende-ring procedures do not address market imper-fections and result in discrimination for the capacities targeted.

This analysis suggests that targeted mecha-nisms such as capacity auction schemes can be considered fall-back solutions that do not address the structural challenges that have led France to introduce a capacity mechanism. This type of mechanism will therefore not be conside-red in the remainder of this report.

52

Revenue from energy market

Revenue from specific mechanisms

reserve mechanism. It is not possible to assess the impact of

capacity mechanisms on consumers solely by comparing the

direct financial effects of these mechanisms, i.e. the surcharge

on tariffs for strategic reserves and capacity prices, shown in

orange. The fact that energy price caps are reached more often

with the strategic reserve mechanism must also be taken into

account. A thorough comparison confirms that if both mecha-

nisms offset the missing money, they will have the same cost

impact on consumers.

2.2.3.2 Provisions to limit the cost of the French

capacity mechanism

Though it is market-wide, the French capacity mechanism also

includes specific provisions intended to limit its cost.

Firstly, though the French capacity mechanism applies to all

capacity, its application is market-based and not through a capa-

city payment. The decision to base the mechanism on a market

price ensures that contributions to security of supply are fairly

compensated. Though all capacities are rewarded, no value is

assigned to overcapacity, and the price corresponds to the bare

minimum required to safeguard security of supply.

Secondly, the fact that the specific economic situations of dif-

ferent types of capacities are taken into account – incumbent

nuclear and facilities benefiting from purchase obligations  –

limits the mechanism’s total financial impact:

> Incumbent nuclear: The Regulated Access to Historical

Nuclear Electricity scheme (Accès Régulé à l’Électricité

Nucléaire Historique  – ARENH) established by the NOME

Act102 allows all suppliers to set rates for their customers

under the same economic conditions as the incumbent

operator. The ARENH price “is representative of the econo-

mic conditions under which electricity is generated at the

power plants”103 in question, based on an addition of costs,

including capacity costs104. The capacity mechanism will not

modify the cost to suppliers of accessing incumbent nuclear

generation, and alternative suppliers will be able to cover a

A comparative theoretical analysis based on market-wide capacity mechanisms and strate-gic reserves shows that they are equivalent in terms of cost. Both mechanisms restore security of supply to the same level as the perfect energy-only market and offset the missing money resul-ting from market imperfections. In both cases, final consumers are called upon to ensure the coverage of fixed costs and the existence of investment incentives.

While the cost to final consumers is the same, finan-cing does not flow through the same channels:

> With market-wide capacity mechanisms, the value of security of supply is reflected exclusi-vely through the capacity market;

> With strategic reserves, some of this value is rewarded through capacity financing and some through higher energy prices.

Cov

erag

e of

fixe

d co

sts

Fixed costs(€/MWh)

Capacity in the market

Missing money

Capacity in the market SR

1. More frequent price spikes

2. SR surcharge

Capacity in the market

1. Capacity price

Figure 12 – Comparison of economic results of capacity in an energy-only market with missing money, a market-wide capacity mechanism and a strategic reserve mechanism

Energy-only marketwith missing money

System with market mechanism applying

to all capacities

System with strategicreserve

53

CHOOSING THE RIGHT CAPACITY MECHANISM FOR FRANCE / 2

large share of their capacity obligation without paying more

than in the current situation. In this regard, the capacity

mechanism will reveal the capacity price integrated into the

ARENH price;

> Facilities benefiting from purchase obligations (wind, photo-

voltaic and cogeneration): The capacity value of these facili-

ties is transferred to consumers through a reduction of their

contribution to public service charges105. The mandatory pur-

chase price thus already includes capacity remuneration for

the technologies in question.

Nuclear power plants and facilities benefiting from feed-in

tariffs (wind, photovoltaic and cogeneration) already include a

capacity component in their prices since their revenue is regu-

lated in order to promote competition in the French electricity

market and renewable development. The capacity mechanism

will reveal the value of this capacity component without crea-

ting additional costs for suppliers to meet their obligation, and

thus without adding to the cost to final consumers.

2.2.4 Economic efficiency in the presence of investment cycles

Economic theory suggests that investment cycles will occur in

industries characterised by leads time before new facilities are

commissioned and low degrees of information and decision-

making coordination (§ 1.2.3). These are characteristics of the

electricity sector. The long-term equilibrium predicted by static

analysis is rarely achieved: capacity investment and retirement

decisions do not produce immediate effects, but instead follow

their own dynamic, resulting in cycles. This dynamic component

has consequences both for security of supply and the economic

efficiency of the power system as a whole.

The economic literature examines how these cycles can be sha-

ped by market architectures and by mechanisms adopted to

ensure adequacy. Capacity mechanisms allow stakeholders to

coordinate their capacity investment and retirement decisions.

In particular, the investment cycle phenomenon that is intrinsic

to the energy-only market can be monitored and mitigated, at

least in part, when capacity mechanisms are in place106.

2.2.4.1 Impact of a market-wide capacity mechanism on

investment cycles

A market-wide capacity mechanism is a tool for quantity-

based regulation that creates the right incentives for capacity

investment and retirement decisions. Though the price signal

is the channel through which information is transmitted, at

102Law 2010-1488 of 7 December 2010 on the New Organisation of the Electricity Market

103Law 2010-1488, Article 1

104Decree 2011-466 of 28 April 2011 setting out the rules governing access to historical nuclear energy, Article 1, V: “The product transferred includes the generation capacity certificate, as defined in article 4-2 of the aforementioned law of 10 February 2000, corresponding to its profile.”

105Law 2013-312 of 15 April 2013 on preparing for the transition to a low-energy system and including a range of provisions for water pricing and wind power, Article 7 sexies: “Buyers of renewable or cogenerated electricity (subject to Purchase Obligations) generated in France assume the responsibilities of the producer of that electricity for delivering the corresponding capacity certificates.” “The value of the capacity certificates acquired within the framework of the contracts [Purchase Obligation] is deducted from the public service charges calculated for the buyer.”

106[De Vries, 2004] shows that a capacity obligation type mechanism is better able to dampen investment cycles. [Stoft, 2002] finds a similar result with a strategic reserve type mechanism.

a fundamental level, coordination is achieved

because market stakeholders can work with the

same volume forecasts.

With centralised mechanisms, quantitative forecasts

are generated administratively. Under decentralised

mechanisms like capacity obligations, total capacity

demand is calculated by aggregating the anticipa-

tions of market stakeholders, factoring smoothing

effects and the level of coverage required into the

method for calculating the obligation. Stakeholders’

decisions are therefore based on quantities, which

prevents overreactions to price signals and copycat

behaviours.

In phases of under-capacity, investments are limited

by total capacity demand. Even if the capacity price

is very high, it will only compensate the amount of

capacity that corresponds to total demand. New

capacity in excess of the amount needed to meet

real needs will not find a buyer. Cyclical effects are

lessened.

Market-wide capacity mechanisms thus send

signals about prices and quantities that help coordi-

nate capacity investment and retirement decisions.

Their stabilising role reduces the intensity of invest-

ment cycles.

2.2.4.2 Investment cycles under a strategic

reserve mechanism

Strategic reserve mechanisms help guarantee

capacity adequacy by influencing both the energy

market price and the amount of capacity available

when supply is tight, thanks to capacity reserves.

A strategic reserve mechanism will address the pro-

blems encountered in the energy-only market by

dynamically adjusting the size of strategic reserves. Any reduc-

tion or increase in reserve volumes will impact the outlook for

capacity remuneration, notably shaping decisions about pulling

older facilities out of the market, as they can earn complemen-

tary revenue by participating in the reserves and thus delay their

shutdown.

If security of supply is at risk, the mechanism operator will

increase the reserves. This impacts market stakeholders’ deci-

sions at two levels. First, the retirement of existing capacities can

54

be delayed if they become part of the reserve. Second, the with-

drawal of capacities from the market will drive up the energy

price, stimulating investment and causing the shutdown of

capacities in the market to be delayed. In the absence of a quan-

tity-based mechanism to prevent overinvestment, stakeholders

will continue to invest heavily and mimic others’ behaviour, as is

seen in the energy-only market.

In situations of overcapacity, the mechanism operator will scale

back the reserves and have no influence on the formation of

the energy price. The strategic reserve mechanism will not limit

copycat behaviours though.

In sum, a strategic reserve mechanism only partially addresses

the issue of the lack of coordination of capacity investment and

retirement decisions. It therefore has only a limited ability to

dampen the investment cycles found in the energy-only mar-

ket, and will not fully correct the structural failures of the market.

2.2.5 Suitability to France’s situation

A decision was made in favour of a market-wide

capacity mechanism because it addresses the speci-

fic challenges facing the French power system. Two

factors support this assertion: this type of mecha-

nism enables the participation of the demand side,

and the size of the strategic reserve required would

be problematic in France.

2.2.5.1 Enabling participation of the demand

side

One of the main reasons France is implementing a capa-

city mechanism is to address the problem posed by

peak demand in winter, when all supply- and demand-

side capacities contribute to security of supply.

A primary objective of the mechanism is to give consumers incen-

tives to make the structure of their consumption more virtuous,

notably to reduce peak demand in winter, as was discussed in

chapter 1. Such incentives only make sense if they apply to all

consumers, proportionately to their consumption. By the same

token, the capacities included must suffice to meet all demand.

This matching of obligations for all consumption with the parti-

cipation of all capacities in the mechanism makes the most eco-

nomic sense and creates the right incentives. It allows demand

response and targeted demand reduction actions to participate

in the mechanism in the same way, either implicitly or expli-

citly107, making the mechanism technology neutral108.

2.2.5.2 Strategic reserve planning with a key low-

probability, high-impact variable

Addressing France’s structural security of supply challenges

with a strategic reserve mechanism would require placing in the

reserve a disproportionate quantity of capacity relative to the

amount that would remain in the energy market.

Indeed, designing a strategic reserve requires establishing a

number of parameters, particularly rules for when reserves are

dispatched and the size of reserves needed to address speci-

fic security of supply considerations. If the strategic reserve is

designed to offset the missing money, then these parameters

are interlinked. Additional revenue earned by capacities outside

the reserve will depend on the likelihood that the reserves will

be dispatched, which in turn depends on the size of the reserve

and the dispatch price109.

However, little information can be found in the economic lite-

rature about the sizing of reserve volumes, with most studies

citing assessments by the bodies in charge of strategic reserves.

In practice, reserve volumes depend in large part on security of

supply needs. For instance, if security of supply would be threa-

tened by the shutdown of a certain number of plants, then the

size of the strategic reserve will be calculated in such a way as to

ensure that they remain in the system.

Bearing this in mind, a strategic reserve in France would have

to be large enough to guarantee security of supply during win-

ter cold spells. However, whereas with a conventional adequacy

assessment it would suffice to calculate the total capacity requi-

red to avert the risk, with a strategic reserve, a distinction must

also be made between the capacity that is “in” and “out of” the

market, i.e. the capacity that must be included in the reserve to

remain economically viable.

107With a market-wide capacity mechanism, a consumer that reduces its peak consumption by 10 MW also reduces its obligation by 10 MW, which is equivalent, for the consumer, to its 10 MW of load reduction being rewarded through certification. With a mechanism targeting only 10% of capacities, a 10 MW reduction in peak consumption reduces the consumer's obligation by 1 MW, which is no longer equivalent to having 10 MW of certified demand response participate in the capacity mechanism.

108The different ways in which demand response can participate in the French capacity mechanism are discussed in detail in part 3.

109“A planner first calculates the optimal volume of generation capacity, then decides the reserve volume and calculates the optimal dispatch price. The reverse is also possible: given a certain reserve dispatch price, the optimal reserve volume can be calculated.” [De Vries, 2004]

Any form of capacity mechanism will allow for a better coordination of capa-city investment and retirement deci-sions than the energy-only market, and will therefore dampen investment cycles. Market-wide capacity mecha-nisms appear more efficient than strategic reserves, particularly when it comes to preventing situations of overcapacity.

55

CHOOSING THE RIGHT CAPACITY MECHANISM FOR FRANCE / 2

The most critical risk in France  – typically a one-in-ten-year cold

spell requiring around 30 hours of load shedding – is a low-proba-

bility, high-impact variable. The likelihood that the capacity needed

to cover this risk would be dispatched is low, meaning it would not

necessarily be economically viable if it earned revenue solely by

generating energy. It can therefore be considered that if a strategic

reserve was used in France, it would have to be large enough to

meet the additional demand recorded during cold spells.

An initial order-of-magnitude assessment of the required reserves

can be based on a brief analysis of winter demand peaks in past

years. In 2008, which is used here as the benchmark (no signifi-

cant cold spell), the highest level of demand recorded was just over

83 GW. In 2012, when a major cold spell occurred, peak demand

exceeded 101  GW. Without considering structural changes in

demand110, we see that 18 GW of capacity had to be available111 to

meet demand in 2012, capacity that was not used in 2008112.

Interconnections between the French power system and the

rest of Europe create opportunities for capacity in France to earn

revenue above and beyond its use to meet domestic demand. A

strategic reserve of 18 GW would therefore undoubtedly be dis-

proportionate. However, the capacity that it would be economi-

cally justifiable to use to meet peak and extreme peak demand

carries high variable costs. It is therefore unlikely that export

prices would be competitive.

To summarise, meeting peak demand in France

with a strategic reserve would require:

> Either a very large strategic reserve, far bigger

than the volume that would be required in other

contexts: Since the reserves would be dispatched

at the price cap on the energy market, the upper

portion of the price duration curve would be

significantly distorted;

> Or a structurally oversized generation mix to ensure

that it could meet peak demand while also produ-

cing energy at competitive prices for exports (peak

demand met with base-load generation).

It seems that both options could result in significant

distortions in energy markets, both in France and

Europe.

110This is an acceptable hypothesis for calculating orders of magnitude, especially as the two dates were relatively close and that the economic environment was not driving a significant increase in demand.

111Taking account of contingencies potentially affecting capacities and constraints that could decrease their availability would require adding a safety margin.

112With no cold spell in the winter of 2013-2014, peak demand did not climb above 85GW, illustrating how it is possible for peak demand to remain relatively low throughout the winter.

113[ACER, 2013]A strategic reserve mechanism would

not be adapted to France’s specific situation. The reserve size required to meet demand during cold spells would be problematic, and market-wide capacity mechanisms seem to offer a more efficient way to promote demand-side participation.

It is possible to adopt different types of models with market-

wide capacity mechanisms. The third key characteristic of the

French mechanism relates to its decentralised nature.

While the mechanism does indeed involve quantity-based regu-

lation, the law stipulates that each supplier will have to secure

enough capacity certificates to cover the consumption of its

own customers during peak periods. This is different from the

single buyer model, an alternative market model that ACER des-

cribes as follows:

A Capacity Auction scheme is a centralised scheme in which

the total required capacity is set (several years) in advance of

supply and procured through an auction by an independent

body. The price is set by the forward auction and paid to all

participants who are successful in the auction. The costs

are charged to the suppliers who charge end consumers.

2.3 Why a decentralised capacity mechanism

Contracted capacity should be available according to the

terms of the contract113.

The French capacity mechanism is a capacity obligation, which

is mainly a system for allocating costs, making market stakehol-

ders accountable and organising trading:

A Capacity Obligation scheme is a decentralised scheme

where obligations are imposed on large consumers and on

load serving entities (“LSE”, further referred to as “suppliers”),

to contract a certain level of capacity linked to their self-

assessed future (e.g. three years ahead) consumption or sup-

ply obligations, respectively. The capacity to be contracted is

typically higher, by a reserve margin determined by an inde-

pendent body, than the level of expected future consumption

or supply obligations. The obligated parties can fulfil their

obligation through ownership of plants, contracting with

56

generators/consumers and/or buying tradable capacity certi-

ficates (issued to capacity providers). Contracted generators/

consumers are required to make the contracted capacity

available to the market in periods of shortages, defined admi-

nistratively or by market prices rising above a threshold level.

Failure to do so may result in penalties. A (secondary) market

for capacity certificates may be established, to promote the

efficient exchange of these certificates between generators/

consumers providing capacity and the obligated parties or

between obligated parties114.

This decision to adopt a decentralised model for the capacity

obligation is a distinctive characteristic of the French mecha-

nism, allowing all suppliers and consumers to be held directly

accountable, above and beyond financing their capacity obliga-

tion. Parties subject to capacity obligations are responsible for

anticipating their capacity needs, securing enough capacity cer-

tificates to cover these needs, and making choices about redu-

cing consumption within their portfolios during peak periods.

They are also financially liable for any positive or negative imba-

lances between their level of coverage and actual needs.

There are three main justifications for adopting this model: it

is compatible with the internal electricity market, it is adapted

to France’s specific situation, notably in terms of the economic

virtues of the incentives created to reduce peak demand, and

lastly the timescales associated with decentralised markets

make them economically efficient.

2.3.1 Compatibility with the philosophy of the European energy market

The system proposed for France is a certificate market. It draws

from a classic economic theory model: to correct the market

failures described in chapter 1, property rights are created for

capacity as a “product”. Public authorities determine parameters

to ensure that their targets will be met. Market stakeholders are

then free to engage in trading within the framework of these

parameters. The assumption that the market will drive optimal

allocation is preserved and taken into account: public authori-

ties do not estimate needs in lieu of market stakeholders.

This choice is in keeping with the founding prin-

ciples of the internal European energy market and

intended solely to expand the range of market

products offered. The principle that market stake-

holders should be accountable for their respective

portfolios is upheld in that they assess their future

needs, decide how they will cover them, and are financially res-

ponsible for imbalances between their actual needs and cove-

rage. Because the architectures of energy and capacity markets

are similar, the roles and responsibilities of different participants

in the power system are consistent. At a time when the Euro-

pean Commission is expressing concerns about the adoption

of capacity mechanisms in Europe, this conceptual proximity to

the “target model” for Europe is a very important consideration.

The alternative to a mechanism with negotiable certificates is the

single buyer model. Models of this type can notably be found in

North America, in systems where the energy market is also cen-

tralised. The United Kingdom has also announced the creation

of a mechanism inspired by this philosophy115. With this type of

system, public authorities, not market stakeholders, evaluate

aggregate needs. This makes sense intellectually, since security

of supply is a public good and transaction costs are lower than

with a decentralised model. However, there are consequences

in terms of how responsibilities are distributed, and the system

explicitly involves capacity development planning.

The debate about the two approaches is informative but

inconclusive, the main criterion being whether the market or

a planner can estimate future needs more accurately. Without

claiming to settle a controversy that may continue amongst

researchers and practitioners for many years to come, some

conclusions can be drawn:

> The single buyer model reduces the risk incurred by inves-

tors by eliminating uncertainty associated with finding buyers

(the single buyer is responsible for acquiring all capacities and

then passing costs through), whereas no risk is transferred

from market stakeholders to the community with a bona fide

decentralised model;

> The single buyer model requires an ex-ante calculation of

the medium-term capacity target (the target is a parameter

exogenous to the functioning of the mechanism), whereas in

the decentralised model stakeholders are responsible for this

(the capacity target is an endogenous parameter that varies as

the mechanism functions);

> The single buyer model exposes the community to the risk

that demand forecasts will become self-fulfilling prophe-

cies, whereas the decentralised model exposes it to the risk

that the market will not function properly if stakeholders are

unable to accurately assess their capacity needs.

There is probably no definitive answer to these questions, as

they must also be considered in the light of how the system

functions as a whole. For this reason, RTE recommended in

114[ACER, 2013]

115[DECC, 2013]

57

CHOOSING THE RIGHT CAPACITY MECHANISM FOR FRANCE / 2

116[RTE, 2011]

117This would be even more feasible if several decentralised capacity mechanisms are in place; see for instance [BDEW, 2013]. Cross-border considerations are addressed in chapter 9 of this report.

118[EC, 2013a]

2011 that a simple adjustment be made, without completely

overhauling the structure of accountability, to avert the risk of

self-fulfilling prophecies:

In an architecture in which all capacity is contracted n years

ahead of time, the capacity obligation can be likened to a

number of MW the community of suppliers must “place”.

Once the total obligation is set, any measures suppliers could

take to reduce power consumption among their customers

will have no impact on the total capacity contracted116.

Two years later, it appears that the reserves that had been iden-

tified in 2011 when evaluating a centralised capacity mecha-

nism for France have increased. Based on trends in the structure

and level of demand, total capacity in the French power system

would more readily require an adjustment than a major structu-

ral increase.

Lastly, choosing a model for the capacity mechanism that is

in keeping with the founding principles of the internal energy

market will also create opportunities to envisage cross-border

functioning going forward117.

2.3.2 Ability to address France’s specific challenges

A decentralised system does not offer many benefits if obliga-

ted parties are passive with regard to their obligations. The main

advantage of a decentralised system  – or a system without a

fixed capacity target – is that suppliers can cover (hedge) their

obligation by buying certificates or making physical adjustments

on the demand side. This creates a good feedback loop for the

capacity price and prevents it from rising above the capacity

value of demand response.

This incentive is logical given the role suppliers play in the current

market architecture: they are in direct contact with consumers

and therefore have exclusive insight into their behaviours and

consumption patterns. Suppliers can influence consumption

structures through their offers and rates. Their involvement in

this regard is a key aspect of the French mechanism’s efficiency.

The resulting model also enables the key to security of supply

in France  – keeping peak demand in check  – to be targeted.

In keeping with the objectives outlined in § 2.2.5.1, demand

response is given its rightful place in the mechanism, as it is

rewarded wherever there is economic space for it. In this sense,

the French capacity mechanism effectively promotes demand

response and lays the groundwork for the energy transition.

These different factors support the assertion that

the main virtue of the decentralised mechanism

relates to allocation, i.e. its ability to send the right

signals to different market stakeholders affected by

the peak demand phenomenon and to encourage

them to take action to hedge the resulting risks at

the least possible cost. Because demand trends do

not become an exogenous factor as would be the

case with a single buyer model, the system should

enable, once demand-side management actions

have been taken, a cost allocation that is fair, pro-

portionate, and reflective of the real responsibilities of each

obligated party when it comes to security of supply. This aspect

of the mechanism is in line with the European Commission’s

recommendations118:

Electricity consumers benefiting from the increased security

of supply should bear the associated cost

[…]

The most effective way of passing costs to the beneficiaries

of enhanced security of supply will normally be through their

electricity suppliers

[…]

In practice this will normally be a function of their consump-

tion at peak load, which requires that customer profiles are

accurate and detailed. This also allows suppliers to pass on

costs to the appropriate consumption groups. Consumers,

and in particular industry, who are able to manage their

demand flexibly should therefore end up paying less towards

the capacity mechanism.

2.3.3 Timescales of the decentralised market and economic efficiency

The economic crisis of 2008 caused demand growth to slow

considerably and showed that centralised capacity planning can

carry a cost for society. If an auction had been organised in 2008

for the years 2011 and 2012, capacity needs would have been

considerably overestimated and excess capacity would have

been subsidised.

A decentralised market model does not reduce this risk (as

explained in chapter 1, market stakeholders as a whole probably

failed to anticipate the effects the crisis would have on demand

or the impact renewable support mechanisms would have on

market prices), but it does not transfer the cost to society either.

In addition, it allows stakeholders with more accurate forecasts

to avoid assuming the related cost.

58

In sum, it is important for a mechanism designed to

regulate capacity levels to be able to adapt to changes

in the economic environment and demand. Decen-

tralised mechanisms appear to be more adaptable, since market

stakeholders trade continuously for several years before the deli-

very year and up until the last minute. Conversely, centralised capa-

city mechanisms function only briefly several years ahead of time.

This adaptability of decentralised capacity mechanisms is one

of the characteristics the European Commission has identified

as a potential way to minimise the cost to consumers, notably

by allowing trading on the secondary market:

Likewise obligations on suppliers relying on decentralised mar-

kets should limit the compensation to capacity to fill the iden-

tified gap to the minimum necessary. Capacity markets also

facilitate secondary trading, which helps to reduces costs119.

Some centralised capacity mechanisms, such as those in use in

North America, have introduced the possibility of subsequent reba-

lancing as a palliative measure. This does not change the fact that

most capacity is “contracted” three or four years ahead of time.

Allowing progressive rebalancing does not make sense if the time

constants associated with developing new capacities are incom-

patible. For instance, if the system is “short” several gigawatts of

capacity two years before delivery, there would not be time to

build enough generation capacities to fill the anticipated gap. The

decree also stipulates that safeguard measures can be taken in

such cases, but not if the projected imbalance is moderate, which

should be the situation in the French power system over the next

few years. The role demand response can play in balancing capa-

city must therefore be considered.

In general, it takes less time to develop demand response than

new generation capacities. With combined-cycle gas turbine

plants, for instance, about five years elapse between the invest-

ment decision and the start of industrial operations, whereas

demand response capacities can be developed more quickly

since less investment is required. This shorter lead time offers

real flexibility when it comes to meeting capacity needs.

The main benefit of this finer timescale is precisely that operators in

the capacity market can leverage all means of managing the sup-

ply-demand balance at their disposal up until the deliver year, par-

ticularly demand-side options. This choice is therefore in line with

the related objectives: give demand response its rightful place in

the mechanism and keep costs low by avoiding reserving too much

capacity ahead of time, regardless of how much is needed.

The choice is also consistent with the management of the

supply-demand balance through the cone of uncertainty. The

farther the date considered from the delivery year, the greater

the uncertainty about how the supply-demand balance will

evolve. Various risks appear over different timeframes, both on

the demand side (economic growth, temperatures) and on the

119[EC, 2013a]

Decentralised mechanism

Centralisedmechanism

Cone of uncertainty

Risk to be covered

A-3 A-1 A A-4

Best estimate of capacity need calculated in a given year

  Capacity need estimated four years ahead with centralised mechanism

  Capacities invested in each year with decentralised mechanism

Figure 13 – The finer timescales of decentralised market architectures reduce the margins required

59

CHOOSINGTHERIGHTCAPACITYMECHANISMFORFRANCE / 2

Illustration:Modeloftheeconomiceffi ciencymadepossiblebythetimescaleofadecentralisedcapacitymechanism

A simplifi ed model can be used to measure the impact of the timescales of centralised and decentralised markets.

Assumptions:Scenarios were generated for four consecutive years factoring in contingencies on the demand and supply sides. Modelled

with independent standard normal distributions, these unknowns are defi ned each year based on a standard deviation in GW.

New investments can potentially be planned based on these variables, to bring the overall system back to equilibrium, within a

maximum volume corresponding to the new capacity that can be added. Parameters were selected in such a way as to repre-

sent credible orders of magnitude for the situation in France. The goal is to not to calculate a specifi c value but rather a simple

estimate of the benefi ts of the fi ner timescale.

Figure 14 – Simplifi ed assumptions used to model variables

Using these scenarios with a Monte Carlo method enables a comparison of the margins required to ensure that the security of

supply criterion will be met with two approaches:

> A centralised mechanism is in place and the capacity needed to meet the security criterion is defi ned four years ahead of time;

> A decentralised mechanism is in place and participants in the capacity market can make use of all available resources, notably

shorter-term options.

This simplifi ed model is an imperfect representation of centralised and decentralised mechanisms, as the timescales of real

mechanisms – both centralised and decentralised – are often fi ner than what is represented here. Nonetheless, it does take into

account that timescales are more fl exible with decentralised mechanisms. Outcomes are not considered in terms of absolute

value but rather in terms of the diff erential between the two classes of mechanism, making the results more signifi cant.

Continuation l

1 1

Y-3 Y-2 Y-1 Y

Y-3 Y-2 Y-1 Y

Y-3 Y-2 Y-1 Y

1 1 1 0,5

1 1

Stan

dard

dev

iati

onca

paci

ty n

eed

Stan

dard

dev

iati

onca

paci

ty n

eed

New

cap

acit

yre

sou

rces

Structuraltrend in demand

Structuraltrend in demand

Structuraltrend in demand

Demandvariable

Demandresponse

Demandresponse

Demandresponse

2

Demandresponse

Changes ingeneration mix

Changes ingeneration mix

Changes ingeneration mix

Availability generation mix

2 2 2

1 1 1

Pea

k pe

riod

GW

GW

GW

60

supply side (trends in the generation mix, power plant availabi-

lity, water availability, etc.). Diff erent resources also become avai-

lable over diff erent timeframes to manage these risks.

The approaches listed above can be summarised as follows:

> One approach involves estimating, four years ahead of time,

the capacity needed to cover the entire cone of uncertainty.

Creating suffi cient margins four years in advance allows secu-

rity targets to be met. This is usually the approach taken with

so-called centralised capacity mechanisms.

> A second approach makes it possible for stakeholders to

estimate capacity needs over the entire four years preceding

the delivery year and to adjust their investments accordingly.

They can make use of all resources at their disposal, particu-

larly shorter-term solutions like demand response. This type of

dynamic approach, which off ers a degree of fl exibility in invest-

ment choices, is possible with decentralised market models.

This analysis confi rms that decentralised mechanisms can do

more than centralised ones to prevent overcapacity, and thus

reduce the cost to consumers. Participants in the capacity market

will do what is necessary to cover capacity needs for a

given year by adjusting their investments at the pace

that best suits them.

In practice, some centralised capacity mechanisms that have

finer timescales: in particular, when capacity needs are eva-

luated four years ahead of time, they can be divided into long-

term investments (generation capacities) and shorter-term

investments, for instance in demand response. However, this

results in more rigidity, with decisions about the respective

weighting of different timeframes made ahead of time at an

administrative level.

Lastly, the option value off ered by short-term measures reduces

excess capacity in the system and therefore the total cost to

participants, while also better dividing the cost of risks between

them. A perfectly predictable consumer will benefi t from signi-

fi cantly lower costs through the reduction in margins, and will

not pay the costs associated with short-term measures. This

allows for a better individualisation of costs and creates the

kind of accountability called for in the European Commission’s

recommendations120:

The costs of capacity mechanisms should be allocated to

consumers in proportion to their contribution to demand

during periods of scarcity or system stress.

Continuation j

ResultsThe study shows that the option to leverage short-term resources in the decentralised mechanism reduces the margins neces-

sary four years in advance by about 2 GW compared with the centralised mechanism. This outcome should be viewed in the light

of initial volume assumptions based on orders of magnitude for the French power system.

With a decentralised mechanism, when actual results correspond to the low capacity needs forecast for a given year, there will

be little (or no) reason to activate short-term resources. Conversely, under the centralised mechanism, additional margins will

have been created four years ahead of time to guarantee coverage in an extreme scenario, resulting in overcapacity. The study

thus shows that the centralised mechanism will create 2 GW of excess capacity every third year on average.

When conditions in the extreme scenario materialise, the margins created under the centralised mechanism will cover the

volumes required in these specifi c circumstances. Under the decentralised mechanism, short-term measures will be necessary

to achieve the same level of security, resulting in additional transaction costs. But in the end, the same amounts will be invested,

in one case because coverage is ensured through margins four years ahead of time, and in the other because shorter-term

measures are introduced over time.

When investments are indeed required for security of supply purposes, the amount of capacity available to the system is the

same under centralised and decentralised mechanisms. On the other hand, when the level of actual demand corresponds to the

lowest forecasts, the centralised capacity mechanism leads to excess capacity that is costly for consumers.

While the study shows that unneeded capacity is avoided by the decentralised mechanism in all scenarios on average, this model

is especially benefi cial in scenarios where margins created to guarantee coverage four years ahead of time prove unnecessary.

120[EC, 2013a]

61

CHOOSING THE RIGHT CAPACITY MECHANISM FOR FRANCE / 2

2.4 Conclusions

The French capacity mechanism is a capacity obligation under-

pinned by three key principles: it is a market mechanism (mar-

ket-based) that applies to all capacity (market-wide) and ope-

rates in a decentralised manner. These principles make the

mechanism adapted to the French system’s specific characte-

ristics and challenges.

A market mechanism was chosen because it creates economic

efficiency, allowing obligated parties to engage in trading to

minimise the cost of their capacity obligation. This choice was

supported by the observation that price-based regulations are

inefficient; the price-based mechanisms adopted in Europe are

currently being reformed, notably capacity payments in Spain,

Italy and Ireland and guaranteed purchase prices intended to

encourage the development of certain technologies in France.

The decision to adopt a market-wide capacity mechanism is

directly correlated to these objectives. For the mechanism to

truly guarantee security of supply, all capacities must partici-

pate. This matching of obligations for all consumption against

the participation of all capacities in the mechanism makes eco-

nomic sense and creates the right incentives for the demand

side to participate.

There are also economic justifications for this choice. The desire

to find structural solutions to the imperfections of the energy

market ruled out targeted “safety net” capacity mechanisms

like one-off tenders as an option. Strategic reserves are ano-

ther type of targeted mechanism that can indeed address the

failures of the energy market if the parameters of the mecha-

nism are perfectly defined, but analysis shows that, even in this

case, the mechanism does not cost less than a market-wide

capacity mechanism. Moreover, strategic reserves appear to be

less efficient than market-wide mechanisms in the presence of

investment cycles. Lastly, the size of the strategic reserve that

would be required in France, factoring in the low-probability,

high-impact variable represented by winter cold spells, would

mean taking a significant share of capacities out of the market,

creating distortions.

The French capacity mechanism will function in a decentralised

manner, applying market design principles similar to those of

the energy market. Obligated parties in the capacity market

must anticipate the needs of their customers and cover these

needs, and are financially liable in the event of imbalances. This

decentralised model preserves the structure of accountability

of energy markets in terms of investments and prevents having

public authorities make decisions in the place of market stake-

holders. On the other hand, transaction costs are higher with

this model.

The benefits of a decentralised model in terms of making par-

ticipants accountable is reflected in its economic efficiency

and cost allocation. A supplier that can accurately anticipate

the needs of its customers, and potentially influence their

consumption, will gain even more from the mechanism. In sum,

this market design is particularly suited to the challenge of redu-

cing peak demand, and also allows obligated parties to choose

between a variety of levers.

The model enables a dynamic approach to consumption trends,

leveraging the expertise of suppliers that interact most directly

with consumers. Not only does it avoid the introduction of a fixed

capacity target that could create incentives to consume more, it

also provides more flexibility since needs can be reassessed over

time. In a situation like 2008, a decentralised mechanism would

typically prevent about 2 GW of overinvestment.

Lastly, though a decentralised market model requires the crea-

tion of mechanisms to authorise transactions between stake-

holders, going forward, these mechanisms can also facilitate a

regional or even European approach, just as the standardisation

of negotiable products and trading conditions served as a basis

for the integration of European energy markets.

62

Article 6 of French Law 2010-1488 of 7 December 2010 on the

new organisation of the electricity market (NOME Act) calls for

the creation of a capacity mechanism in France:

Each supplier contributes, in accordance with the demand

characteristics of its customers, in terms of power and energy,

to the security of electricity supply in continental France.

Every electricity supplier must provide direct or indirect gua-

rantees of demand response or electricity generation capa-

city that can be called upon to balance supply and demand in

continental France, particularly during periods when demand

is highest among all consumers.

The law defines some key characteristics of the French capacity

mechanism. It is based on an obligation assigned to suppliers to hold

sufficient capacity certificates to satisfy the demand of

their customers, notably during peak periods, and on

the possibility for obligated parties to acquire certifi-

cates from third parties: therefore, from the outset, this

is a market in which certificates can be traded. The law

calls for this mechanism’s exact mode of functioning to

be defined in a Council of State decree121.

3.1.1 Drafting of the capacity mechanism decree

While preparing the decree on the capacity mechanism, the

Energy Minister entrusted RTE with the preparation of a report

suggesting principles for the mechanism’s organisation and

functioning, in accordance with the provisions of article 6 of the

NOME Act. This report was prepared on the basis of a consul-

tation with market stakeholders and submitted to the Energy

Minister on 1 October 2011. It notably proposed that all genera-

tion and demand response capacities participate in the mecha-

nism, that capacities be rewarded solely in exchange for effective

commitments, and that a decentralised market architecture be

implemented, based on principles similar to those of the energy

market, meaning market stakeholders would be accountable for

their contributions to security of supply. This is, in principle, the

model described in chapter 2 of the present document.

The report contained detailed proposals that were the subject of

a second consultation, conducted by the French administration

as part of the decree drafting process provided for in the law. This

consultation opened in November 2011 and closed in March

2012. Proposals contained in the initial report were debated,

3. GUIDELINES FOR THE CAPACITY MECHANISM RULES The market mechanisms implemented in Europe are showing

evidence of failure in several areas, as discussed in chapter 1 of

this report. These imperfections are raising questions about the

energy-only market’s ability to guarantee security of supply on

its own. Public intervention is justified, especially as the funda-

mentals of the power system are being turned on their head by

the ambitious energy transition policies introduced by Member

States in Europe and by peak demand growth in France.

Different types of capacity mechanism design are possible.

Chapter 2 of this report presented the justifications for the

model chosen for the French capacity mechanism: it is a mar-

ket mechanism (market-based) with quantity-based regulation,

applicable to all capacities (market-wide) and functioning in a

decentralised manner.

These principles were laid down in the decree of December

2012, and must now be put into practice. This is the purpose

of the draft rules published by RTE on 9 April 2014. The step at

hand is all-important since it involves defining the specific pro-

cedures that will determine in large part how the mechanism

functions.

This chapter begins with a review of the legislative and regula-

tory frameworks governing the capacity mechanism and from

which the architectural principles applied were drawn (§ 3.1). It

then describes the fundamental orientations RTE proposes in

the draft capacity mechanism rules to ensure that it will effecti-

vely reward capacities for their contribution to security of supply

(§ 3.2).

121 The provisions of article 6 of the NOME Act are codified in articles L. 335-1 to L.335-8 of the Energy Code. Article L. 335-6 establishes that the terms of application shall be defined in a

3.1 Architectural principles set forth in laws and regulations

63

GUIDELINES FOR THE CAPACITY MECHANISM RULES / 3

clarified or amended. For instance, a “safety net” mechanism

was introduced for situations of “exceptional risk” to security of

supply122. All issues discussed in the rest of this document (form

of the obligation, certification methods, nature of settlement,

mechanism transparency, regulation of dominant operator’s

market power, recognition of cross-border interconnections, etc.)

were addressed, often in great detail, during these discussions.

The Government sought the opinions of the Energy Regula-

tory Commission and Competition Authority while preparing

the decree. Their opinions, issued in the spring of 2012, led the

Government to make changes to the draft decree, the defini-

tive version of which was published in December 2012 (not all

changes are mentioned in this report). These opinions were also

taken into account while the mechanism rules were being draf-

ted in 2013.

3.1.1.1 Energy Regulatory Commission deliberation

In its deliberation of 29 March 2012123, the Energy Regulatory

Commission supported public authorities in terms of the market

design selected for the capacity mechanism, issuing a favourable

opinion on the draft decree, subject to certain modifications.

The Energy Regulatory Commission approved the choice of

a decentralised market mechanism the parameters of which

would reflect suppliers’ contributions to the shortfall risk, the

decision to reward the contributions of capacities to safeguar-

ding security of supply, and the option to hold market partici-

pants accountable.

Its observations were accompanied by proposed amendments

to improve how the mechanism would function, notably by

strengthening the provisions designed to make market stake-

holders accountable, but did not question the overall equilibrium

of the choices the Government proposed. Several amendments

made to the draft decree regarding the functioning of the capa-

city market reflected CRE’s recommendations:

CRE proposes to include in the draft decree a provision

allowing capacity rebalancing by suppliers, prior to verification

that they have met their obligation.

Imbalance settlement for capacity portfolio managers will be

key to the mechanism’s efficiency.

The concept of a reference capacity price should be intro-

duced in the draft decree: its method of calculation will be

determined by CRE124.

On the other hand, the Government did not adopt

the Energy Regulatory Commission’s proposal to

eliminate the transitional safety net mechanism

and the tendering mechanism for the delivery year

including the 2015-2016 winter. This has no impact

on the draft rules published on 9 April 2014: these

proposals did not relate to the general organisation

or functioning of the capacity mechanism that RTE

was to describe in the rules, but to provisions for

which RTE is not expected to make proposals.

The Energy Regulatory Commission also considers

that some features of the proposed mechanism can

“mitigate or manage the risk125“ that the mecha-

nism will have an unfavourable impact on competition. It notes

that, as part of its market monitoring activities, it will ensure that

the capacity mechanism does not restrict competition. The pro-

visions designed to prevent manipulation in the capacity market

are discussed in chapter 7 of this report.

Lastly, the Energy Regulatory Commission notes that the impli-

cit recognition of interconnections in the calculation of suppliers’

capacity obligation is an appropriate solution for the short term,

but that coordination should be organised at the European level,

or at least at the regional level, to allow for the explicit participation

of foreign capacity in reducing the shortfall risk. Chapter 9 of this

report discusses the participation of foreign capacity in detail.

3.1.1.2 Opinion of the Competition Authority

In its opinion published on 12 April 2012126, France’s Competi-

tion Authority expressed some concerns about the draft decree

based on its competitive assessment of the provisions submit-

ted to it by the Government.

The Competition Authority initially questioned whether it was

necessary to introduce a capacity mechanism in France and said

it regretted that the Government had not conducted an impact

assessment. On this point, chapters 1 and 8 of this report include

a discussion of the justifications for public intervention and consi-

derations for assessing the consequences and economic impact

of the mechanism described in the capacity mechanism rules.

Thus, in response to the Competition Authority’s concerns, the

justification for public intervention has been clarified.

The Competition Authority’s reservations do not call into

question the fundamental choices in favour of a market-wide

capacity mechanism and decentralised architecture. Instead,

they focus on the risks associated with the mechanism’s

decree of the Council of State.

122 System wherein the minister can organise a tender to secure enough capacity to face an exceptional risk.

123[CRE, 2012]

124[CRE, 2012]

125[CRE, 2012]

126[Competition Authority, 2012a]

64

transparency and complexity, and the concern that these could

distort competition and create barriers for new entrants to the

electricity market. These will be valuable considerations in terms

of defining specific rules for the mechanism’s functioning and

ensuring that market monitoring is efficient once the mecha-

nism is operational.

Having expressed its reservations and in the aim of making

the capacity mechanism more competitive, the Competi-

tion Authority stressed to the Government the importance

of taking into account competition-related risks and impacts

at every stage of the mechanism design process and during

implementation. It made several recommendations on the

proposals in the decree:

> Require that EDF inform CRE of all capacity transfer prices;

> Require accounting separation between EDF’s generation

and supply activities;

> Require that availability forecasts submitted for genera-

tors’ facilities be based on the historical availability of those

facilities;

> Factor in the contribution of interconnections to mitigating

the shortfall risk through a public auction of the correspon-

ding capacity certificates, allocating the proceeds to contri-

butions to public service charges;

> Envisage a legislative amendment applying to entities that

buy directly on wholesale markets to ensure that all rele-

vant participants are subject to the capacity obligation;

> Plan to avoid issuing certificates to facilities that benefit

from purchase obligations insofar as the feed-in tariffs at

which electricity is purchased from these facilities already

cover their costs in full;

> Do not have alternative suppliers assume the cost of the

transitional tendering mechanism.

The draft decree was amended to take some of the Compe-

tition Authority’s recommendations into account. Moreover,

in preparing the draft rules for the mechanism, RTE took the

competitive landscape described by the Authority into consi-

deration: the mechanism introduced in France is, in this regard,

a closely regulated and monitored market mechanism. Special

care was taken to ensure that stakeholders have access to all

relevant information and to facilitate monitoring and control

by the Energy Regulatory Commission. Along these lines, the

rules include provisions to ensure that the parameters of the

mechanism are visible and stable, transparency measures

relating to the physical underlyings of the mechanism and

the forecast security of supply situation, and transparency

measures relating to the functioning of the market, particularly

transaction volumes and prices.

Details of RTE’s proposals regarding the explicit participation

of foreign capacity in the capacity mechanism can be found in

chapter 9.

3.1.2 Provisions laid down in the decree

After consulting with power system stakeholders and inde-

pendent administrative authorities, the Government published

Decree 2012-1405 of 14 December 2012 relative to the contri-

bution of suppliers to security of electricity supply and to the crea-

tion of a capacity obligation mechanism in the electricity sector in

the Official Journal of the French Republic on 18 December 2012.

It establishes the general organisational structure of the French

capacity mechanism and is based on the principle, discussed in

chapter 2 of this report, of a decentralised, market-wide capacity

mechanism that makes all stakeholders accountable for their

contributions to security of supply. Suppliers must cover their

obligation based on effective consumption of their customers

and can acquire capacity certificates from operators. A decen-

tralised market model was chosen to hold stakeholders accoun-

table, and suppliers are thus induced to engage in trading to

cover their obligations as accurately as possible. Capacities are

certified in exchange for operators committing to make them

available. Lastly, all participants have financial incentives to meet

their commitments.

Chapters 1 and 2 of the decree stipulate that suppliers’ capacity

obligations and capacity operators’ certifications are calculated,

respectively, based on assessments of their contributions to

the shortfall risk or reducing it. These provisions are consistent

with the goal of implementing a capacity mechanism that truly

enhances security of supply.

This has significant consequences for the architecture of the

mechanism: suppliers’ obligations are calculated on the basis of

the contribution of their customers to the shortfall risk; it is the

structure of the shortfall risk that determines how certificates

are allocated to capacities, taking into account their technical

characteristics.

The decree notably defines how suppliers’ obligations are to be

determined (§ 3.1.2.1), the principles applied in certifying capa-

city (§ 3.1.2.2) and how the trading of capacity certificates will be

organised (§ 3.1.2.3).

65

GUIDELINESFORTHECAPACITYMECHANISMRULES / 3

3.1.2.1 Capacity obligation assigned to suppliers

For each delivery year, suppliers are required to hold capacity

certifi cates corresponding to the eff ective consumption of their

customers (including transmission and distribution system ope-

rators, for their losses) in order to meet the security of supply

objective mentioned in Article L.335-2 of the Energy Code.

The decree lays down the principles governing capacity certifi-

cate trading between obligated parties. It calls for the setting of

a deadline for trading capacity certificates (transfer deadline),

after which capacity certificates can no longer be traded, along

with a settlement deadline, by which time each supplier must

settle the amount corresponding to the imbalance between

its capacity obligation and the amount of capacity certificates

it holds.

3.1.2.2 Certifi cation of generation and demand

response capacities

Capacity operators commit to a certain level of capacity (certi-

fi ed capacity level) and are issued the corresponding amount of

capacity certifi cates. Capacity operators are affi liated with capa-

city portfolio managers.

At the end of the delivery year, RTE calculates, for each capacity

portfolio manager, the diff erence between the sum of certifi ed

capacity levels within its portfolio, refl ecting the self-assessment-

based commitments of capacity operators, and eff ective capa-

city levels. The capacity portfolio manager is fi nancially liable for

the amount of the settlement imbalance thus calculated.

During a capacity mechanism term, and prior to the delivery

year, capacity operators can make upward or downward reba-

lancings to refl ect changes in the projected availability of their

capacities.

3.1.2.3 Functioning of the capacity mechanism

The Energy Regulatory Commission monitors the functioning of

the capacity certifi cate market to ensure that the signals sent to

market stakeholders are meaningful and support the objective

of safeguarding security of supply.

To facilitate trading and the monitoring of the market, the

decree includes several provisions relating to the mechanism’s

transparency, and notably specifi es that RTE is to create and

maintain three registers for each delivery year:

Figure 15 – General organisation of the mechanism (timeline)

Phase 1Setting of parameters

Phase 2Y-4 à Y-1

Phase 3Delivery year

Phase 4Post-notification

Data collectionand capacity verification

by system operators

Calculationby systemoperators

of suppliers’reference

power

Capacity certificationand rebalancing

(Organised market sessions)

Certificate trading(self-supply, bilateral contracts)

4 years

Certification deadlines

Rebalancing

Publications by RTE(estimated capacity certificate requirements)

Certificate trading

Settlement,CPMs

Settlement,suppliers

…

Transferdeadline

Transparencyand publication

of parameters formechanism

term

Effectivecapacity

notification

Supplierobligation

notification

Start of term(opening ofregisters for

the yearin question)

SDB (supply-demandbalance) study

Peakperiods…

66

> The certified capacities register, a public document, lis-

ting all certified capacities connected to the transmission or

distribution systems. RTE describes all characteristics of the

capacities, the amount of power certified, and the capacities’

projected availability (updated);

> The capacity certificates register, not made public, which

records in a secure manner all transactions involving the

issuance, transfer or destruction of capacity certificates;

> The peak demand-side management register.

A capacity mechanism term is a multi-year scheme that starts

four years before the delivery year and ends two years after the

delivery year. The general timeline of the mechanism is pres-

ented in Figure 15.

The capacity mechanism term begins when the obligation and

certification parameters are published, which is also when the

certified capacities and capacity certificates registers are crea-

ted for the delivery year. RTE simultaneously publishes its initial

estimate of the capacity certificates required for all suppliers’

obligations to be met. This estimate factors in an evaluation of

the contribution of interconnections to reducing the shortfall

risk (see chapter 9).

Capacity operators can at this point request to have their capaci-

ties certified, in exchange for which they will receive capacity cer-

tificates. Capacities that can be developed very quickly, such as

demand response capacities, can be certified up until the start of

the delivery period. Operators can make adjustments to the data

submitted with capacity certification requests until the end of the

delivery period thanks to a flexible rebalancing process.

Approval Scheme

Approved by Minister on a proposal from RTE after consulting CRE

Approved by CRE

Approved by CRE on a proposal from RTE

Defined by CRE after consulting RTE

Decision made by Minister on a proposal from CRE (considered accepted if not contested within three months)

Approved by Minister on a proposal from CRE

Defined by CRE

Figure 16 – Regulatory framework provided for in the decree

RULES CONTRACTS OTHER TEXTS

Provisions defining delivery years and peak periods

Provisions relating to the obligation: > Calculation of reference

power; > Calculation of

obligation;> Unit power for capacity

certificate and capacity certificate recovery

Provisions relating to certification:> Certification method

and verifications;> Adaptation procedures

for capacity with reduced contributions to supply;

> Rebalancing of capacity operators and settlement for rebalancing.

Certification contract 

DSO-Operator contract 

CPM/RTE contract 

DSO/TSO exchange agreements for

calculating reference power

DSO/TSO exchange agreements for

certification

DSO/TSO/operators on procedures

and deadlines for sending information

and organising information flows

Calculation method for actual demand within small and large consumer subcategory

Calculation method for actual demand within subcategory buying for losses

Procedures and amount of incurred expenses recovered by grid system operators for calculating

and sending obligation-related data

Calculation method for unit price of “supplier” settlement

Procedures for redistributing account balances

Amounts and recovery procedures for obligation-related expenses

Procedures for keeping registers

Calculation method and allocation schedule for ARENH certificates

Calculation method for certificates linked to transfer tariffs

Calculation method for reference price

Format and schedule for provisions relating to overall certificate levels

Procedures for gathering data on transactions

67

GUIDELINES FOR THE CAPACITY MECHANISM RULES / 3

Once the first capacity certificates have been issued, suppliers

can begin to cover their obligations, based on their own fore-

casts and risk hedging strategies, by acquiring capacity certifi-

cates from operators or securing capacity certificates for their

own capacities. Capacity certificates can be traded until the

transfer deadline, which is after the delivery year.

During the delivery year, data relating to the operation of capa-

cities is gathered and verified, particularly information about

actual availability during the peak period associated with

certification (PP2 period). Consumers’ actual demand is also

measured.

At the end of the delivery period, effective capacity levels are

calculated for all capacities, based on data collected during

the delivery year. Effective capacity levels are then aggrega-

ted for capacity portfolios. This aggregate is compared with

the sum of the certified capacity levels of capacity portfolio

managers. If an imbalance is found, the capacity portfolio

manager must pay an imbalance settlement corresponding

to that difference.

A supplier’s obligation is calculated based on observed

consumption and the obligation parameters defined before the

term begins. Each supplier is informed of its obligation before

the transfer deadline. Once this deadline has passed, the diffe-

rence between a supplier’s obligation and the amount of certi-

ficates held in its account in the capacity certificates register is

calculated, and the supplier is notified of any imbalance. It must

pay any resulting imbalance settlement.

3.1.3 Regulatory framework provided for in the decree

The next step in implementing the decree involves defining the

rules, contracts and conventions that will allow the capacity

mechanism to function properly. As with any market mecha-

nism, it should be possible for these aspects to be adapted more

quickly, since they do not call into question the general prin-

ciples of the mechanism.

The decree stipulates that the capacity mechanism rules are

to be approved by the Energy Minister, based on proposals

submitted by RTE, after the Energy Regulatory Commission

has issued an opinion. It also calls for the drafting of various

conventions and contracts that will complement the capacity

mechanism rules, subject to approval by the Energy Regula-

tory Commission.

To give an overall view of the mechanism and make it easier to

understand, in July 2013 RTE proposed a major simplification,

offering to analyse the mechanism as a whole, without taking

into account the numerous channels of approval mentioned

in the decree (see figure 16). This approach also means that

the proposals subject to approval by the Energy Minister and

those subject to approval by the Energy Regulatory Commis-

sion are being submitted together. By default, each article

of the RTE proposal is a proposal for a provision of the rules,

i.e. the text that must be approved by the Minister. [CRE] is

mentioned in the body of the title when articles are proposed

for inclusion in the provisions to be approved by CRE. No dis-

tinction is made between these provisions in the rest of this

report.

RTE drafted its proposal after a stakeholder consultation. It is not

proposed as a regulatory act: the provisions it contains can be

modified at the initiative of the Minister or CRE in the course of

the regulatory decision-making process, which will include ano-

ther stakeholder consultation. In this area, the process under

way in France is similar to what is being done at the European

scale between ENTSO-E, ACER and the European Commission

regarding the preparation of network codes.

3.1.3.1 Consultation of market stakeholders organised

by RTE

RTE organised a consultation through the Transmission System

Users’ Committee (Comité des clients Utilisateurs du Réseau de

Transport d’Électricité – CURTE), which brings together all stake-

holders in the French electricity market (generators, suppliers,

traders, demand-side operators and power exchanges), consu-

mer groups, and distribution system operators. The CURTE’s

work is open to representatives of the Energy Regulatory Com-

mission and the French administration, and to interested third

parties (academics for instance). A workgroup focusing speci-

fically on the capacity mechanism, hosted by the CURTE’s Mar-

ket Access Commission, consolidated all of the work carried out

during the consultation period.

Thanks to the diversity and commitment of the participants

involved, all aspects of the mechanism were analysed. Electri-

city market stakeholders took advantage of the consultation to

present their positions on the different building blocks of the

draft capacity mechanism rules. Participants worked together at

an intense pace (22 working meetings, 76 written contributions,

52 in-session presentations, one simulation tool made available

to participants).

68

The consultation was organised in two phases (see fi gure 17).

The fi rst (January to July 2013) was devoted to preparing a draft

of the capacity mechanism rules. These draft rules were the

subject of a public consultation that opened on 11 September

2013 and continued for six weeks. More than 500 comments

were received, detailed responses to which are included in an

appendix to the draft rules.

The second phase (September to December) provided an

opportunity for stakeholders to propose changes and for RTE

to propose amendments to the draft rules. The goal during this

phase was to strike the right balance between the desire to hold

market stakeholders accountable and create real and proportio-

nate incentives – which requires a clarifi cation and individualisa-

tion of the provisions suggested in the rules – and the benefi ts

to stakeholders in terms of forecasting if the relative stability of

the mechanism’s functioning was guaranteed, notably through

the introduction of normative provisions.

RTE considers that the amendments to the draft rules pro-

posed based on the consultation of September 2013 make the

mechanism more transparent and predictable, and strike a good

balance between constraints of diff erent types.

RTE would like to thank all participants for their quality contri-

butions, which made the consultation a forum for rich and

constructive debate and generated concrete proposals for the

implementation of the capacity mechanism, in keeping with the

provisions of the decree.

Figure 17: Consultation timeline

Q1 - 2013 Q2 - 2013 Q3 - 2013 Q4 - 2013 2014

Jan Feb Mar Apr May June July Aug Sep Oct Nov Dec …

Draftrules

Preparation of draft rules(parameters, general outline, specification) Submission

to CRE and Minister

Review by CRE

Finalisationof rules

Consultationon draft

rules

Approvalprocess

MAC mtg 10/04General progress

report andcoordination

of efforts

MAC mtg 11/07Overview ofconsultation

work

MAC mtg 18/12Progress reportpost feedback

Ministerialapproval

Rules

CREopinion

69

GUIDELINES FOR THE CAPACITY MECHANISM RULES / 3

Chapters 1 and 2 of this report discussed the central role the

mechanism must play in correcting how the energy market

functions and safeguarding security of supply.

The decree clarified the provisions of the NOME Act and suppor-

ted the principle of a decentralised, market-wide mechanism,

and the mechanism rules outline the key ideas and parameters

that will determine in large part how the mechanism functions.

For RTE, it was essential that these choices take into account the

importance of safeguarding security of supply and keeping the

mechanism proportionate to its purpose. Oftentimes the debate

centred on finding a balance between the need to individualise

the provisions of the rules on the one hand and the benefits of

stabilising some parameters, to reduce uncertainty for market

stakeholders, on the other.

Five key definitions are a particularly good reflection of these

objectives, and they are presented in the sections below: (1)

the nature of capacity commitments, (2) the periods during

which capacities are committed, (3) the parameters for cal-

culating capacity obligations and certifying capacities, (4) the

reference data used to calculate obligations and certify capa-

cities, and (5) the methods for assigning a value to demand

response.

3.2.1 Nature of commitments by capacity operators (installed or available capacity)

During the consultations of 2011 and 2013, the nature of the

commitments made by capacity operators was a key point of

discussions with market stakeholders. The two approaches that

emerged involved commitments based on installed capacities

and commitments based on the availability of generation or

demand response capacities.

Mechanisms based on installed capacities aim to ensure that

sufficient generation or demand response capacities exist to

cover the shortfall risk, without considering whether these capa-

cities will effectively be available when security of supply is at

risk. Conversely, mechanisms based on commitments to make

capacity available aim to guarantee that enough capacities will

effectively be available to cover the shortfall risk during peak

demand periods.

These approaches have very different consequences both for

the nature of the mechanism and the level of security of supply,

and the impact on market stakeholders will not be the same.

Capacity operators can be asked to make commitments for ins-

talled capacities to ensure the physical existence of the capa-

cities, in exchange for capacity remuneration. But there is no

guarantee that the capacities remunerated will be effectively

available when needed to safeguard security of supply, particu-

larly during peak demand periods. In theory, it can be assumed

that the energy market will naturally create incentives for ope-

rators to make their capacities available during peak periods.

However, insofar as the capacity obligation mechanism involves,

from the consumer’s perspective, taking out insurance that

power will be supplied even when supply is tight, it seems logical

that the cost incurred by the final consumer should bring with

it an extra guarantee that power will be supplied: the mecha-

nism must therefore make capacity remuneration conditional

upon operators effectively making capacities available, instead

of rewarding them merely because the capacities exist.

Mechanisms based on installed capacities can also make secu-

ring capacity remuneration a priority over contributing to secu-

rity of supply, since they are explicitly geared to creating a favou-

rable environment for investment and avoiding revenue deficit

situations.

Lastly, mechanisms based on installed capacities can create

entry barriers for demand response. Stakeholders will seek to

cover their needs by focusing on creating new capacities for the

long term, on the basis of forecasts in which demand may be

fixed at a set value. This approach to covering long-term needs

prevents the participation of capacities that can be developed

with shorter time constants, such as demand response.

In sum, a mechanism that rewards installed capacities is not

consistent with the end-goals of the capacity mechanism. In

particular, the commitments that result in capacity certifica-

tion do not reflect the real physical needs of the power system,

and in this sense such mechanisms do not serve the primary

purpose of contributing to security of supply.

On the other hand, a mechanism that rewards commitments to

make capacity available has several advantages.

3.2 Purpose of the capacity mechanism rules: Guarantee real contributions to security of supply

70

First, it is designed to guarantee that the capacities

needed to avert shortfalls are eff ectively available

when security of supply is at risk; it therefore applies

to all capacities that are available when needed by the system.

The mechanism provides a form of insurance when it comes to

security of supply: capacities are rewarded through the mecha-

nism for being available when security of supply is at risk, or in

other words as a direct result of their eff ective contribution to

security of supply. Commitments to make capacities available

are the trade-off for the remuneration of all capacities.

Second, this type of mechanism allows demand response to

participate in the exact same way as generation capacities: the

functioning of the mechanism thus allows competition between

the two types of capacities.

3.2.2 Duration of capacity commitments

Chapter 1 of this report described how temperature sensitivity

is the key characteristic of the French power system and how

peak demand has been growing steadily (§ 1.2). Bearing this in

mind, the adequacy assessments conducted by RTE show that

the impact of temperatures on demand is the main risk for the

French power system and that situations of exceptional demand

determine the contours of the shortfall landscape127.

The shortfall risk clearly corresponds to a risk of exceptionally

high demand, i.e. the risk of an intense cold spell.

During the consultation, two approaches were presented for

determining the period over which operators must commit their

capacities to cover the shortfall risk:

> The fi rst called for capacities to be committed for the entire

period during which shortfalls could occur (“winter period”,

from 1 November to 31 March). In this case, the commitment

period is defi ned based on a calendar variable. Each month is

weighted based on the shortfall probability associated with it.

> The second called for capacity commitments to target the

periods during which demand is highest. The commitment

period is in this case based on a demand variable.

The illustration below (fi gure 19) provides a graphical represen-

tation of the two approaches. The chart of the left represents the

month-by-month breakdown of the shortfall risk with a maxi-

mum in January (commitment period defi ned based on calen-

dar variable). The chart on the right represents the breakdown

of shortfall risks based on consumption levels. It illustrates the

approach wherein capacity commitment periods are based on

a demand variable.

To ensure that the capacity mechanism focuses on contribu-

tions to reducing the shortfall risk, RTE proposes the adoption

of the approach that bases capacity commitment periods on a

demand variable, given the direct and decisive impact demand

levels have on the shortfall risk.

Indeed, probabilistic adequacy studies show that the shortfall risk

increases with demand. In each shortfall scenario, shortfall hours

correspond systematically to hours when demand is highest.

127All shortfall situations considered, see fi gure 19.

RTE’s draft rules support a mechanism that rewards capacities based on eff ective availability, in line with the security of supply objective and the founding principles of the mechanism (par-ticipation of demand response, recognition of all capacities).

Figure 18 – Illustration of the shortfall landscape comparing supply and demand simulations

ShortfallSupplyDemand

30

50

70

90

GW

Shortfalllandscape

71

GUIDELINESFORTHECAPACITYMECHANISMRULES / 3

The following observations are worthy of note:

> The 50 hours during which demand is highest include 100%

of the shortfall hours in two thirds of the situations in which

shortfalls occur, and, in the most unfavourable scenario, just

under 40% of shortfall hours;

> Beyond the 150/200  hours when demand is highest, 100%

of the shortfall hours are included in 90% of the situations

with shortfalls, and these 150/200 hours of highest demand

include at least 80% of shortfalls in all cases.

In reality, the calendar variable is merely a realisation of the

demand variable: the shortfall probability is at its highest in

January simply because this is the month during which the pro-

bability of an intense cold spell is greatest.

Moreover, basing commitment periods on times when the

shortfall risk is greatest makes the periods more targeted, mea-

ning the capacity mechanism will not have any eff ects outside

the periods during which it is truly needed.

3.2.3 Methods for calculating the obligation and certifying capacity

Articles 3 and 10  of the decree stipulate, respectively, that

methods must be determined for calculating the obligation of

capacity suppliers and certifying and verifying capacities. The

decree states that these methods must focus on meeting the

security of supply objective in a proportionate manner.

3.2.3.1 Parameters for determining the method of

calculating the capacity obligation

With the architecture selected for the capacity mechanism, sup-

pliers’ contributions to the shortfall risk are translated into a spe-

cifi c capacity obligation for each supplier.

A suppliers’ capacity obligation is calculated based on its refe-

rence power – refl ecting its consumption during peak periods –

and on various parameters that are the same for all suppliers,

including a security factor that notably refl ects the margins

required to cover residual risks (excluding temperature risks).

These parameters are unrelated to the physical determinants of

suppliers’ contributions to the shortfall risk (temperature sensiti-

vity, fl exibility, etc.). To ensure that suppliers’ capacity obligations

are proportionate and allow the security of supply target to be

met, these parameters must be defi ned in the capacity mecha-

nism rules in such a way as to refl ect the physical contribution

of each supplier to the shortfall risk as accurately as possible.

Figure 19 – illustration des deux approches permettant d’apprécier le risque de défaillance(Source : RTE, GT du 02/04)

 Non-shortfall situations

 Shortfall situations

Time-based approach to describingshortfall landscape

Demand-based approach todescribing shortfall landscape

Shortfall landscape Probshortage

(t) Shortfall landscape : Probshortage

(C)

Shortfall landscape

25%

20%

15%

10%

5%

0%0%

20%

40%

60%

< 73 GWJuly

August

Septem

ber

October

Novem

ber

December

January

Febru

ary

MarchApril

May

73-75

75-77

77-79

79-81

81-83

83-85

85-87

87-89

89-91

91-93

93-95

95-97

97-99

99-101

101-103

> 103 GW

June

Proba(C) = t

Proba(t) = C

RTE’s draft capacity mechanism rules therefore recommend that capacity commitments be defi -ned based on a demand approach – targeting so-called PP2 periods – since this approach is rele-vant in evaluating the shortfall risk and prevents the capacity mechanism from producing eff ects when it is not needed.

72

3.2.3.2 Parameters for certifying capacity

Generation and demand response capacities effectively contri-

bute to reducing the shortfall risk by being available when secu-

rity of supply is at risk, and therefore during cold spells. Their

actual contribution to reducing the shortfall risk also depends

on the number of hours during which they can be dispatched

within these periods.

With the architecture selected for the capacity mechanism, a

capacity’s contribution to reducing the shortfall risk is translated

into an amount of capacity certificates specific to each capacity

and issued to the operator of that capacity.

The amount of capacity certificates issued is calculated based on

the available power declared for the capacity – or in other words

the capacity that can be dispatched during peak periods – and on

certification parameters that are the same for all capacity operators.

These parameters take the form of coefficients so as to reflect the

impact of a capacity’s technical constraints on its effective contri-

bution to reducing the shortfall risk, such as energy constraints

(daily and weekly) and controllability constraints. The certification

parameters defined in the rules must reflect the real impact of

technical constraints on a capacity’s contribution to reducing the

shortfall risk to ensure that the amount of certificates issued to the

capacity accurately reflects its impact on security of supply.

3.2.4 Reference data used to calculate obligations and certifications

The preceding sections stressed the amount of care taken in

defining the principles and methodologies to be applied in esti-

mating the effective contributions of all market stakeholders to

the shortfall risk for each mechanism parameter proposed in the

rules. One important principle relates to the type of data used to

determine the reference power of suppliers in order to calculate

their capacity obligation and to determine the available power

of capacities to calculate their amount of certificates.

Regarding suppliers’ obligations, the reference power used to

calculate the capacity obligation reflects their contribution to

the shortfall risk (§ 3.2.3.1). The decree stipulates that reference

power is calculated based on observed demand. The consump-

tion recorded for the delivery year should therefore be conside-

red the reference for calculating reference power.

Regarding capacity certification, it is easy to define the available

power of a capacity during shortfall hours for years when short-

falls occur: it suffices to measure the capacity’s active use during

those hours. However, shortfalls do not occur in most years. The

question thus relates to the most meaningful way to measure

a capacity’s effective contribution to security of supply during

years without shortfall situations.

Several means of measuring available power are possible, and

they are summarised within the two approaches below:

> The first considers that the level of availability obser-

ved during the delivery year must be used as the basis for

verifying an operator’s effective contribution to security of

supply. This approach involves individualising capacity levels;

it is consistent with the goal of holding market stakeholders

accountable and recognising capacities’ effective contribu-

tions to reducing the shortfall risk. For instance, two opera-

tors with the same type of capacity can have different rates

of effective availability, and this has a direct influence on their

contribution to reducing the shortfall risk. This approach is

also consistent with the choice made about the calculation of

reference power to determine the amount of suppliers’ capa-

city obligations;

> The second approach involves using normative values in the

certification process. By definition, these normative values

do not fit with actual results. With a normative approach,

the contribution of some capacities is set to values that do

not match observed reality. In this regard, it strays from the

objective of making market stakeholders accountable and

The parameters defined in the rules for calcu-lating capacity obligations must allow the real contribution of each supplier to the shortfall risk to be reflected. It was with this principle in mind that the capacity obligation parameters were set, to ensure that two consumers with the same contribution to the shortfall risk are assigned the same capacity obligation. The parameters for calculating capacity obligations are discussed in more detail in chapter 4 of this report.

Certification parameters must be defined in the rules in such a way as to reflect the real impact of a capacity’s constraints on its contribution to reducing the shortfall risk, and therefore its contribution to security of supply. It was with this principle in mind that the certification para-meters were set, to ensure that two capacities making the same contribution to reducing the shortfall risk are issued the same amount of cer-tificates. Certification parameters are discussed in more detail in chapter 5 of this report.

73

GUIDELINES FOR THE CAPACITY MECHANISM RULES / 3

ensuring that capacity levels defined do indeed correspond to

contributions to reducing the shortfall risk. However, certain

stakeholders consider that this approach must be used due to

the intermittent nature of some capacities, given the exoge-

nous nature of the risks to which those capacities are exposed

(availability of the primary resource).

3.2.5 Methods of valuing demand response

The French capacity mechanism was designed to address the

issue of peak demand growth, or in other words as a means

of modifying consumption behaviours during peak periods

(demand-based approach) and encouraging sufficient invest-

ment by complementing the price signals generated by energy

markets (supply-based approach). The capacity mechanism

must be able to stimulate investments that promote the eco-

nomic management of peak demand, meaning it must allow

demand response to play its rightful role in ensuring capacity

adequacy in the system. As such, the participation of demand

should not be seen as a mere feature of the capacity mecha-

nism’s design but rather as one of the main reasons for its

implementation.

The architecture of the mechanism encourages the partici-

pation of demand response by providing two ways for it to be

rewarded: it can be recognised “implicitly”, via a reduction in a

supplier’s capacity obligation, or “explicitly”, if demand response

capacity is certified and issued capacity certificates.

Demand response is rewarded implicitly when peak demand

management actions are taken directly by suppliers to reduce

their customers’ consumption during peak periods. Insofar

as the capacity obligation is calculated based on customers’

consumption during peak periods, these demand-side manage-

ment efforts immediately reduce the capacity obligation of the

supplier in question.

Demand response is explicitly rewarded when it participates

in the certification process. In this case the demand response

capacity is awarded an amount of certificates that reflects its

contribution to reducing the shortfall risk, based on methodolo-

gies and parameters similar to those used for generation capa-

cities. Demand response capacities that are activated either

directly by a consumer or through an aggregator can thus parti-

cipate directly in the capacity market in the same was as gene-

ration capacities.

The capacity mechanism rules call for adjustments to be

made for load reductions when certified demand response

capacity is activated, to prevent it from being counted twice,

both implicitly and explicitly, as this would result in the

amount of capacity physically available being insufficient to

cover the shortfall risk. The decree also lays down the prin-

ciple that there should be no discrimination between reduc-

tions in capacity obligations and the certification of demand

response capacity.

To comply with this non-discrimination principle and ensure

that demand response effectively contributes to security of sup-

ply, the methods used to estimate the contribution of demand

response and the related periods both for reductions in the obli-

gation and capacity certification must be consistent. RTE pro-

poses that the following principles be applied:

> Certification: Demand response capacities must commit to

be available during the period considered to calculate the

amount of capacity certificates (PP2) to be certified;

> Obligation: For demand response to result in a reduction of

a supplier’s capacity obligation, it must be activated during

the period considered to calculate the capacity obligation

(PP1).

RTE proposes that priority be given to methods and parameters that incorporate the values observed during the delivery year. This approach allows as much information as possible about the state of the system to be taken into account and to identify the real contribution of each market stakeholder to security of supply.

In the interest of finding a balance between the needs for individualisation and stability, RTE introduced an additional provision for the cer-tification of intermittent capacity: the overall scheme is similar to the one for controllable capacity, with the risk relating to the primary source accounted for on the basis of self-assess-ments with observed availability measured.

The rules include an optionality principle, leaving it up to capacity operators to choose between this scheme and one that includes normative values and neutralises the risks associated with the primary energy source. A coefficient is in this case applied to ensure that the certified capacity level reflects the technologies’ average contribu-tion to reducing the shortfall risk.

This approach addresses the expectations expressed during the consultation while allowing operators that are capable of hedging the varia-bility of their capacity (notably by backing it up with flexible capacity such as demand response) to fully benefit from this coverage.

74

The provisions proposed by RTE relative to the definition of methods of calculating capacity obligations and capa-city certifications ensure that there is no discrimination between the two ways of rewarding demand response capacities and therefore that these capacities effectively contribute to security of supply.

These proposals are discussed in detail in chapters 4 and 5 of this report.

Figure 20 – Valuing demand response through the capacity mechanism

3.3 Conclusions

Article 6 of the NOME Act calls for the creation of a capacity

obligation mechanism and for the principles underpinning the

functioning of this capacity obligation mechanism to be laid

down in a Council of State decree128.

The publication in the Official Journal of the decree relative to

the contribution of suppliers to security of electricity supply and

the creation of a capacity obligation mechanism in the electri-

city sector followed a consultation with power system stake-

holders organised by public authorities, taking into account

RTE’s proposals for the implementation of a capacity obligation

mechanism. France’s Energy Regulatory Commission and Com-

petition Authority were also consulted by the Government and

asked to issue opinions on the draft decree.

The decree is based on three pillars: the concept of

shortfall risk, the obligation for suppliers to hold capa-

city certificates, and the obligation for capacity opera-

tors to certify their capacities through contracts.

According to the provisions of the decree, suppliers

are obligated to hold, for each delivery year, an

amount of capacity certificates corresponding to the observed

consumption of each consumer, while transmission and distri-

bution system operators must hold an amount equivalent to

their estimated losses, to meet the security of supply objective;

operators of generation and demand response capacities are

required to enter into certification contracts with RTE for their

capacities, through which they commit to a specific capacity

level. The decree also specifies how the obligations assigned to

suppliers are to be determined, lists the principles to be applied

in certifying operators’ capacities, and describes how capacity

certificate trading is to be organised.

The decree stipulates that the capacity mechanism rules are to be

approved by the Energy Minister, based on proposals by RTE and

after the Energy Regulatory Commission has issued its opinion. In

preparing the draft rules, RTE organised a consultation with mar-

ket stakeholders in 2013, the goal of which was to draft capacity

mechanism rules that would (i) comply with the provisions of the

decree, (ii) translate into practice the priority of recognising real

contributions to security of supply, and (iii) balance the need to

individualise the provisions of the rules with the need to ensure a

degree of stability in the mechanism’s functioning.

Must be available during the period for which genera-tion capacity is committed to be available – PP2

Certified demand response

Must be activated during the reference period for calculating the obligation – PP1

Non-certified demand response

Ten-year results for extreme peak demand response activated one in ten years.

Demand response available during every PP2

period but activated only during one PP2 period

Demand response activated during every PP1 period,

i.e. during ten PP1 periods.

128The provisions of article 6 of the NOME Act are codified in articles L. 335-1 to L.335-8 of the Energy Code. Article L. 335-6 establishes that the terms of application shall be defined in a decree of the Council of State.

75

GUIDELINES FOR THE CAPACITY MECHANISM RULES / 3

Five key choices are particularly illustrative of how the three

principles were taken into account:

> A mechanism based on available capacity is consistent with

the proposal to adopt a market-wide capacity mechanism and

ensure that capacities are rewarded based on their real contri-

bution to security of supply;

> Using a demand-based approach to define the capacity com-

mitment period – i.e. securing commitments for the periods

when demand is highest – is a way to ensure that the capacity

mechanism’s effects target the needs of the power system

when security of supply is threatened;

> The parameters used for calculating suppliers’ capacity obliga-

tion – such as the security factor – and the amount of certifi-

cates issued for capacity – for instance technical constraints

impacting the capacity’s contribution to reducing the shortfall

risk – must be set in such a way as to reflect as accurately as

possible the real contribution of suppliers to the shortfall risk

and the real contribution of capacities to reducing the short-

fall risk;

> Taking into account realised values for consumption and

capacity availability during the delivery year allows the contri-

bution of each market stakeholder to security of supply to

be recognised. Small imbalances between the data submit-

ted and actual results lead to a mere adjustment. To ensure

a balance between this need for individualisation and market

stakeholders’ request for stability and predictability, a norma-

tive approach can also be taken in calculating capacity levels

for intermittent capacity;

> The methods used to calculate capacity obligations and certify

capacity must be defined in such a way as to guarantee non-dis-

crimination between the implicit and explicit valuation of demand

response. To ensure that demand response capacities effectively

contribute to security of supply, capacities that are certified must

be subjected to the same availability commitments as generation

capacities during the period considered (PP2), and demand-side

management measures factored into the reduction of suppliers’

obligations must be effectively activated during the period consi-

dered for the calculation of the obligation (PP1).

76

4. CAPACITY OBLIGATION

This chapter discusses the provisions concerning the calcula-

tion of the obligation for obligated parties. It begins with a review

of the general provisions governing the capacity obligation, i.e.

the identification of parties subject to the obligation, the defi-

nition of reference power and observed consumption, and the

time periods and methods applied in calculating the obligation

(§ 4.1). Details are then provided about the options selected in

RTE’s proposal regarding the definition of the PP1 period during

which the capacity obligation is calculated (§ 4.2), the definition

of the delivery year (§ 4.3) and the parameters for calculating

the capacity obligation (§ 4.4). The last sections of the chapter

present the exact formula used to determine the capacity obli-

gation (§ 4.5) and the obligation timetable for suppliers during a

capacity mechanism term (§ 4.6).

4.1 General provisions regarding the obligation

In accordance with article L. 335-1 of the Energy Code, capa-

city obligation refers to the obligation for any obligated party to

contribute to security of electricity supply by having valid capa-

city certificates for each delivery year.

The decree stipulates that the amount of a supplier’s obligation

“is calculated based on the reference power of its customers

and a security factor taking account of the shortfall risk.”

4.1.1 Obligated parties

The obligation capacity created by the NOME Act of 7 Decem-

ber 2010 applied to electricity suppliers. Taking into account the

recommendations made while the decree was being drafted, the

range of market stakeholders subject to the capacity obligation

was expanded by the Brottes Act of 15 April 2013 (article 15):

“End consumers and system operators, for their losses, that,

for all or part of their consumption, are not supplied by a

supplier, contribute, in accordance with the characteristics

of this consumption, in power and in energy, in mainland

France, to electricity supply security. For the application of

this chapter, they are subject to the provisions applicable to

suppliers.”

This change was intended to ensure that all consumers would

be subject to the capacity obligation, and that the obligations

calculated would be consistent with national consumption.

For the application of these provisions, the rules use the term

“obligated party” to refer to any market stakeholder subject to a

capacity obligation, not just suppliers. The following are defined

as obligated parties under the rules:

> Suppliers, as parties that purchase electricity for sale to end

consumers or system operators (for their losses) and have an

administrative permit;

> End consumers not supplied, for all or part of their consump-

tion, by a supplier;

> System operators, for their losses, when they are not supplied

by a supplier.

4.1.2 Reference power

The decree stipulates that the reference power of an electricity

consumer “reflects its contribution to the shortfall risk during

the delivery year in question.” System operators calculate and

communicate to RTE the reference power of the end consu-

mers connected to their systems, per supplier.

To reflect differences in the treatment of consumers depending

on whether they are remote-read, profiled or buying for losses,

reference power is broken down into three categories: profiled

reference power, remote read reference power and reference

power for the supply of losses.

For each type of consumer, the calculation method is based on

the following principles:

> Inclusion of consumption observed during the peak period

(PP1 period defined below);

> Adjustment for the temperature sensitivity of consumption;

> Adjustment for certified demand response capacities activa-

ted during the PP1 period.

77

CAPACITY OBLIGATION / 4

4.1.2.1 PP1 peak period

The PP1 peak period is the reference period for determining

the obligation of each obligated party. It comprises the hours

during which consumption is measured to calculate reference

power and, ultimately, to determine the amount of the capacity

obligation.

The PP1 period is defined in such a way as to meet the following

two objectives:

> PP1 hours must be the best metric for reflecting, in the obliga-

tion of an obligated party, the real contribution of the consu-

mers within its perimeter to the shortfall risk;

> It must be possible for peak demand management to be

rewarded through a reduction in the obligation, in accordance

with the objectives outlined in chapter 1 of this report and the

goal of fully integrating peak demand management into the

mechanism.

4.1.2.2 Observed consumption

The decree of December 2012 stipulates that “reference

power is calculated based on the observed consumption of

each consumer”129. The obligation is thus not determined on

the basis of predefined standards but rather on measured

data, in order to allocate to each consumer its real contribu-

tion to the shortfall risk. This would be incompatible with a

model in which a party’s obligation would represent a portion

of the total obligation determined separately. In the French

system, observed consumption during PP1 hours constitutes

the basis for calculating the capacity obligation of each obli-

gated party.

The basic data used to calculate the observed consumption

of a consumer are taken from the metering and information

systems of the operators of public systems to which the sites

are connected directly or indirectly. This principle is in keeping

with the regulatory framework governing the energy industry as

a whole, but could create difficulties when it comes to profiled

consumers since their load curve is not measured but rather

estimated based on normative profiles. Pending the deploy-

ment of new metering systems enabling more dynamic assign-

ment of energy flows, the provisions adopted in the rules are

based on the existing systems, particularly the profiling system

that enables a load curve to be reconstituted for each site equip-

ped with a meter indicating readings. The provisions authorising

the explicit valuation of demand response through the capacity

market (see chapter 5) allow this difficulty to be circumvented by

utilising demand-side operators’ facilities to certify their demand

response potential, provided that these facilities comply with

the regulatory framework governing the market

(NEBEF) or the balancing mechanism, i.e. that they

qualify under the rules in effect.

A reference base is used to calculate the observed consump-

tion associated with each obligated party for the calculation

of its reference power: the perimeter of the obligated party.

This perimeter makes it possible to identify a site’s affilia-

tion with a party for the calculation of the obligation, and

addresses cases where sites are associated with multiple

obligated parties.

4.1.2.3 Taking into account the temperature

sensitivity of consumption

The temperature sensitivity of consumption is defined as the

established link, below a certain temperature, between elec-

tricity consumption and temperature. It represents the rapid

response of consumption to a variation in temperature and is

therefore to be distinguished from the cyclical/seasonal com-

ponent of the consumption curve.

Consumption in France has been growing steadily more sensi-

tive to temperatures in the past ten years, and this is a defining

characteristic of the French power system. RTE estimates that

the winter gradient at 7pm increased by 35% between the win-

ter of 2001-2002 and the winter of 2011-2012. This increase

is largely responsible for the peak demand growth discussed in

section 1.2 of this report.

For the capacity mechanism to achieve its security of supply

objective, the sum of the temperature sensitivities considered in

the mechanism must correspond to the temperature sensitivity

observed in France as a whole during the delivery year.

4.1.2.3.1  Characterisation of temperature sensitivity

The link between power and temperature is considered to be

linear. This hypothesis is confirmed by the shape of the scatter

plot obtained when we represent a temperature on the X-axis

and the corresponding consumption of the group of sites stu-

died on the Y-axis.

We observe that below a threshold temperature, the variation

in demand is proportional to the variation in temperature. In

practice, the gradient is the slope of the scatter plot. Above the

threshold temperature, demand is not affected by the tempera-

ture variation.

129Decree 2012-1405, Article 1.

78

30

40

50

60

70

80

90

-5 0 5 10 15 20 25

Gradient

Actual national temperature [°C]

Threshold temperature =

15°CMea

sure

d E

RD

F po

wer

[GW

]

Figure 22 – Illustration of threshold temperature(Source: ERDF, WG of 09/07/13)

80

90

100

50

60

70

 

30

40

50

  Dai

ly a

vera

ge p

ower

(GW

)

20

‐10 -5 0 5 10 15 20 25 30

Actual temperature (°C)

Heating gradient

Figure 21 – Illustration of the heating gradient in France(Source: ERDF, WG of 19/02/13)

 2012

 1996

7pm points in year of delivery RT8

ERDF data

79

CAPACITY OBLIGATION / 4

Little is seen of the “overheating” gradient for very cold tempe-

ratures; it is therefore not taken into account.

4.1.2.3.2  Determinants of temperature sensitivity

Temperature sensitivity is characterised by 48 half-hourly gra-

dients for a given year, smoothed temperatures and a thres-

hold temperature. The following concepts are used in the rules.

Smoothed temperature

The temperatures used in the capacity mechanism correspond to

variables derived from the raw temperature measured on various

weather stations. It is necessary to construct a temperature herei-

nafter referred to as the “smoothed temperature”  – and not to

take raw temperatures – in order to constitute an effective expla-

natory variable of consumption. This temperature is in particular

smoothed to take into account the thermal inertia of buildings.

Threshold temperature

The threshold temperature corresponds to the temperature

below which a variation in temperature is considered to lead to

a variation in consumption. It basically refers to the temperature

below which heating is switched on.

Gradient

The link between power and smoothed temperature, conside-

red for a delivery year, is reflected by a temperature sensitivity

gradient (the slope of the curve) that is constant for a given year.

The link between power and temperature is not uniform over a

day. Forty-eight half-hourly gradients are therefore defined for

each half hour of the day.

4.1.2.3.3  Extreme temperature

In order to reflect the contribution of a consumer to the short-

fall risk due to its temperature sensitivity, the obligation must be

calculated based not on the consumption observed during the

delivery year but on an estimate of this consumption during a

severe cold spell corresponding to the risk against which the sys-

tem is trying to protect itself (one-in-ten-year cold conditions).

For this purpose, the use of an extreme temperature was pro-

posed during the consultation and is adopted in the rules, thus

enabling translation to a cold spell.

In concrete terms, consumption levels observed are translated to

those estimated at this extreme temperature. It is as if the cold spell

defined by this extreme temperature, corresponding to one-in-

ten-year cold conditions, actually occurred each year. The capacity

mechanism is thus similar to an insurance mechanism

providing coverage against an extreme situation with

the level of risk referred to in the security criterion defi-

ned by public authorities. The capacity mechanism

thus enables expected income from capacities to

be stabilised, by spreading out over each year reve-

nue that would otherwise be concentrated in a cold

spell with a probability of occurrence of once every ten years.

4.1.2.4 Adjustment for power reduced by activating

certified demand response capacity

Adjustments are made to reflect the load reduced through the

activation of certified capacity to prevent demand response

from being double counted. Indeed, as discussed in § 3.2.5,

demand response can be valued either through a reduction of

the capacity obligation or directly through the issue of capacity

certificates. It is important to ensure that the same load reduc-

tion is not counted twice, as this would distort competition

between stakeholders and result in a physical volume of capa-

city that is insufficient to meet the security of supply criterion.

The provision adopted in the rules for adjusting for load reduc-

tions through the activation of certified capacity involves adding

the load reductions in question to observed consumption.

4.1.3 Security factor

4.1.3.1 Provisions of the decree

The security factor is intended to meet the requirements set by the

law and decree whereby suppliers’ capacity obligation “encourages

compliance in the medium term with the required level of electri-

city supply security130”, in accordance with the general principle of

making stakeholders accountable for the risks they generate.

The decree stipulates that the security factor “[takes] account of

the shortfall risk” and that “the effect [of interconnections of the

French electricity market with other European markets] is incor-

porated in the determination of the security factor”.

The security factor applies to all obligated parties, making it a

“mutualising” parameter. It only integrates those determinants

of security of supply that are not taken into account through

other means. Roughly speaking, as regards obligations, refe-

rence power already reflects consumers’ contributions to the

shortfall risk, and similarly, on the certification side, certified

capacity131 reflects the contribution of capacity to reducing the

shortfall risk. The security factor included in the rules is thus

exclusively meant to reflect:

130Article L.335-2 of the Energy Code

131Concept discussed in detail in chapter 5 of this report.

80

> The contribution of interconnections to secu-

rity of supply;

> The margins necessary to cover residuals risks,

particularly on demand (other than tempera-

ture sensitivity risk).

The principles applied in determining the security factor, inclu-

ding methodology issues, are described in § 4.4.3. These prin-

ciples and the procedures for changing the security factor are

described in the capacity mechanism rules. The initial numerical

value of the security factor is indicated in the rules, which stipu-

late that any change in this value must be specifically approved

by the Minister.

4.1.3.2 Sensitivity of the security factor to the choice of

the extreme temperature

The determination of the extreme temperature and that of the

security factor are linked. It is thus possible to define several

pairs of values [extT;securityF] that produce the same overall

level of certificates necessary for compliance with the security

of supply criterion132, though the breakdowns between stake-

holders are not the same.

The simplified example below illustrates how the choice of the

extreme temperature influences the security factor. It is based

on the following hypotheses:

> The volume of certificates allocated to the reference mix is

1,000 MW;

> All French consumers are divided between two suppliers,

S1 and S2, the latter being temperature sensitive and the

former not;

> The customer portfolio of S1 is not temperature sensitive and

power demand among its customers on PP1 is 400 MW;

> The customer portfolio of S2 is temperature sensitive with a

gradient estimated at 100 MW/°C. Power demand among its

customers on PP1 is 400 MW.

Four cases are considered with different extreme temperatures:

0°C, -2°C, -3°C and -6°C. It is then possible to calculate for each

of these cases the reference power for S1 and S2 and the cor-

responding total for France.

Case 1 Case 2 Case 3 Case 4

extT (°C) 0 -2 -3 -6

RefP S1 (MW) 400 400 400 400

RefP S2 (MW) 300 500 600 900

RefP France (MW) 700 900 1,000 1,300

The total sum of the obligations must correspond to the volume

of certificates of the reference mix (1,000 MW) for the obligation

to provide an incentive for compliance with the security crite-

rion. It is therefore possible to determine the security factor that

enables compliance with this criterion, and thus the obligation

of suppliers S1 and S2.

Case 1 Case 2 Case 3 Case 4

securityF 1,43 1,11 1,00 0,77

Obligation S1 (MW) 571 444 400 308

Obligation S2 (MW) 429 556 600 692

Total obligation (MW) 1,000 1,000 1,000 1,000

It can therefore be seen that the choice of the two parameters

of the obligation, the extreme temperature and the security fac-

tor, has major redistributive effects between temperature sensi-

tive and non-temperature sensitive consumers.

4.1.4 Summary of obligation principles

4.1.4.1 Formulae

In compliance with the provisions of the decree and in the light

of the abovementioned considerations, it is proposed that the

formulae for calculating the obligation be expressed in the fol-

lowing form.

An obligated party’s obligation is calculated based on its refe-

rence power and the security factor.

Oblig,OP,DY = RefP,DY,OP x SF,DY

> Oblig,OP,DY is the obligation of the obligated party OP for

delivery year DY;

> RefP,DYL,OP is the reference power of the obligated party

OP for delivery year DY;

> SF,DY is the security factor for delivery year DY.

The option chosen in the rules is to make stake-holders accountable for the risks they generate. The temperature sensitivity risk is entirely taken into account by the “extreme temperature” para-meter. It would have been possible to increase the security factor to integrate a portion of the French power system’s temperature sensitivity, but this would have meant assigning a portion of the climate contingency to all obligated parties even though different consumers’ contributions to this risk vary greatly.

132The quantity of certificates needed to meet the security of supply criterion is determined based on the reference mix described in section 4.4.3.

81

CAPACITY OBLIGATION / 4

Reference power is calculated at the level of individual obligated

parties:

> Based on observed consumption, minus the load reduced by

activating certified demand response capacities within a peri-

meter during the PP1 peak period,

> Adjusting for the temperature sensitivity of consumption,

expressed through a gradient, in order to extrapolate obser-

ved consumption to consumption at the extreme tempera-

ture (close to -2.6°C, corresponding to one-in-ten-year cold

conditions).

If ∑tEPP1 ObservedConsumpOP,DY[t] = 0 then refP, DY, OP is set at 0.

> GradientOP,DY[t] is the gradient of the obligated party OP in

half-hourly step t in delivery year DY;

> AdjustedConsumpOP,DY[t] is the observed consumption

of the obligated party OP, in half-hourly step t in delivery

year DY, adjusted for certified demand response capacity

activated;

> ExtT[t] is the extreme temperature, in half-hourly step t, in

delivery year DY;

> SFT, AL[t] is the smoothed France temperature in half-hourly

step t, in delivery year DY;

> nbPP1Hours,DY is the number of PP1 peak period hours in

delivery year DY.

4.1.4.2 Chronological summary of the obligation process

For the first two delivery years, the rules adopt specific provi-

sions making it possible to take into account:

> A specific first delivery year (from 30  November 2016 to

31 December 2017 with July and August excluded) enabling

transition to a delivery year matching the calendar year;

> A shorter period between the start of the term and the deli-

very year. The rules directly incorporate the mechanism para-

meters for these two years.

Once the system is established, i.e. as of the third delivery year,

the chronology of the obligation process under the capacity

mechanism will be as follows:

01/01 DY-4

01/01 DY-2

01/01 DY-2

01/12 DY+201/01

31/1231/03

01/11

Publication of overall obligation

level

DELIVERY YEAR

DELIVERY

15/12 DY+2

15/02 DY+3

Obligationnotification

Transferdeadline

Collectiondeadline

Publication of parameters

–extT, Secu Fact

01/01 DY-3

Imbalancenotification

date

20/12 DY+2

DY

PERIOD

PP1 PP1

Publication of overall obligation

level

Publication of overall obligation

level

Publication of overall obligation

level

refP,DY OP =1

2 x nbPP1Hours,DYx ∑ [AdjustedConsumpOP,DY[t] + GradientOP,DY[t]

x (ExtT[t] – SFT,AL[t])]tEPP1

As explained above, the PP1 period is defined in such a way as to

meet the following two objectives:

> Create the best metric to reflect, through reference power, a

consumer’s contribution to the shortfall risk;

> Encourage the activation of peak demand management mea-

sures, rewarded by a reduction of the obligation, to contribute

to the reduction of peak demand.

4.2 Period for measuring suppliers’ obligation: The PP1 peak period

Consequently, the provision adopted in the rules corresponds to

a targeted PP1 period that is limited in volume and focuses on

the hours when actual consumption is highest. This PP1 period

is part of a delivery year corresponding, with the exception of

the first year, to a calendar year (01/01/YY to 31/12/YY). The

considerations underpinning the provision concerning the deli-

very year are described in § 4.3.

82

4.2.1 Defi nition of PP1 and contribution to the shortfall risk

Given the high level of temperature sensitivity in

France, the shortfall risk is currently concentrated

on the hours of highest demand. The synchrony

between an individual’s consumption and overall consump-

tion in France therefore heavily infl uences its contribution to

the shortfall risk. A consumer that does not consume during

hours of high consumption does not contribute to the short-

fall risk; its reference power should therefore be nil.

This principle was borne in mind when choosing between long

periods, which enable the obligation level to be stabilised but

result in the obligation being pooled among consumers, and

short periods, which target more precisely the periods during

which the shortfall risk is highest and thus enable diff erentiation

between consumers’ contributions to the shortfall risk.

4.2.1.1 Illustration of the impact of the defi nition of PP1

on the reference power of a consumer

The defi nition of the PP1 hours may heavily aff ect the reference

power of individual consumers, particularly non-temperature

sensitive ones. In the illustration in fi gure 23, consumer A (a

typical consumer contributing considerably to peak demand)

and consumer B (a typical consumer moderating its consump-

tion during demand peaks) see their reference power increase

or decrease by 50% depending on whether only hours of high

consumption or all hours are taken into account.

To uphold the provision of the decree concerning accountabi-

lity in proportion to the shortfall risk, the PP1 period must target

the hours of highest consumption for a volume representing

all hours during which shortfall has a signifi cant probability of

occurring.

With a “long” PP1 (potentially the whole weighted winter), hours

of low consumption would be used to estimate a consumer’s

contribution to the shortfall risk. Consequently, the obligation of

a consumer that does not consume during the hours of highest

consumption might not be nil, even though its contribution

to the shortfall risk is nil. The rules proposed by RTE make this

impossible.

4.2.1.2 Impact of the duration of PP1 on the value

allocated to a peak demand management measure

A consumer’s obligation must refl ect its consumption during

the hours when demand is highest. Moreover, in accordance

with the provision of the decree relating to non-discrimination

between certifi ed demand response and reductions in the obli-

gation through load reductions, all peak demand management

measures must be rewarded in proportion to their contribu-

tion to reducing the shortfall risk. Choosing a short PP1 period

is more in keeping with this principle since it avoids diluting

the value of peak demand management measures, which can

contribute substantially to reducing the shortfall risk.

To be accounted for through a reduction in the obligation, peak

demand management measures must be taken during PP1. The

PP1 volume thus determines the activation potential required.

For peak demand management measures to be valued propor-

tionately to the shortfall risk avoided, the scope of the activation

potential must refl ect the shortfall landscape133.

In fi gure 24, the red curve represents the obligation reduction

obtained for a peak demand management measure activated

for 50 hours as a function of the duration of PP1. The blue curve

represents the contribution to the reduction of the shortfall risk

as a function of the number of hours demand response capacity

is activated.

Thus, activation over a period of 50 hours contributes approxi-

mately 88% to reducing the shortfall risk compared with demand

response with no activation limit. If PP1 is very short, for example

less than 50 hours, the peak demand management measure’s

Figure 23 – Demand in France is at its highest between H4 and H6

Con

sum

ptio

n o

fa

few

cu

stom

ers

(MW

)

Fran

ce c

onsu

mpt

ion

(MW

)

600

400

500

100

200

300

0

H1 H2 H3 H4 H5 H6

120,000

80,000

100,000

20,000

40,000

60,000

0

Demandpeakpeak

Heures dans PP1H1 à 6 H4 à 6Puissance de référence A 200 300Puissance de référence B 200 100

 Customer A  Customer B France consumption

PP1 hours

H1 to 6 H4 to 6

Reference power A 200 300

Reference power B 200 100

133For certifi ed demand response capacity, this dimension is taken into account, in certifi cation terms, through the Kd and Kw coeffi cients (see section 5.3.2).

83

CAPACITY OBLIGATION / 4

134These studies and their results are presented in sections 4.2.4 (for France as a whole) and 4.3.4 (individual obligations) of this report.Heures dans PP1H1 à 6 H4 à 6Puissance de référence A 200 300Puissance de référence B 200 100

eff ect will be entirely taken into account in the reduction of the

obligation. If PP1 is long, a much smaller share of the measure’s

eff ect will be counted in the reduction of the obligation even

though its contribution to reducing the shortfall risk is the same.

The defi nition of the PP1 period must therefore be consistent

with the blue curve so that the impact of a peak demand mana-

gement measure on the reduction of the obligation refl ects

its contribution to reducing the shortfall risk, following two

principles:

> It must be based on the hours of highest consumption, indica-

tive of shortfall risk periods;

> It must be based on a volume of approximately 100  to

150 hours.

4.2.2 Defi nition of PP1 and peak demand management

Basing PP1 on the hours when observed consumption is

highest is also a means of encouraging active peak demand

management. It gives suppliers a real solution for managing the

Figure 24 – Peak demand management measure and contribution to reducing the shortfall risk

Contribution to reducing the shortfall risk

Reduction of obligation for peak demand-side management activated  for 50h

Number of hours of activation / Duration of PP1

Red

uct

ion

of s

hor

tfal

l ris

k

51 101 151 201 251 301 351 40110%

20%

40%

60%

80%

100%

risk the obligation represents for them: activating

demand response capacity or other peak demand

management measures. The mechanism proposed

thus ensures that the economic incentives off ered

to market stakeholders correspond to the physical

needs associated with security of supply, the goal

being to approach the economic optimum.

This choice should be considered in the light of other valid

considerations for defi ning the PP1 period. During the consulta-

tion RTE organised in 2013, some suppliers supported the idea

of a long PP1 period, saying it would stabilise the obligation for

stakeholders by neutralising the uncertainty associated with the

location in time of PP1 hours. RTE conducted studies134 to esti-

mate the sensitivity of the obligation to the eff ective distribu-

tion of PP1 hours: these studies showed that the sensitivity was

non-signifi cant.

Most importantly, the alternative scenario involving a long PP1

period would make the signifi cation of the obligation and incen-

tives to reduce peak demand less representative. The less PP1

corresponds to real cold spells, the weaker the incentive to

reduce loads at the right time. With a long PP1 period (all winter,

weighted by shortfall probabilities), the economic incentive for

suppliers to initiate demand management measures with their

customers is greatly diluted. An action to reduce peak demand

would have to be repeated every day in winter to produce the

same reduction in the obligation: the eff ort required to reduce

the obligation by reducing loads during peak periods would be

disproportionate to the real needs of the system, and this would

As defi ned in the rules, the PP1 period:

> Targets periods of high consumption;

> Covers a time period that is consistent with the typical duration of shortfall episodes, enabling peak load reductions to be rewarded in propor-tion to their contribution to reducing the short-fall risk.

84

make no economic sense with regard to the chal-

lenges the French power system is currently facing.

There is also a chance that the timing of demand-

side management measures would not correspond

to peak load periods. For instance, consumers would

be incentivised to reduce consumption during

months with the highest shortfall probability  –

notably January  – and to consume during other

months. In February of 2012, such a system would

typically not have created any incentive for consu-

mers/suppliers to reduce consumption at the peak

time. The system might even have knock-on effects,

encouraging some consumers to stop in January

and then resume consumption early in February.

The benefits associated with a short PP1 period tar-

geting actual peaks in demand are not as great for

profiled consumers, due to the limitations intrinsic

to a profiling system that does not allow consu-

mers’ specific contributions to peak demand to

be identified with accuracy135. Ultimately, the only way for the

value created for the system to be accurately measured would

be either to replace the profiling scheme with one allowing

the individual treatment of each consumer (not planned as

of today, even after smart meters are rolled out) or to create

profiles for suppliers based on their offerings. In the meantime,

as indicated above, the direct valuation of the load reduction

potential of these consumers in calculating capacity sup-

ply (certification of demand response capacity) provides the

most benefits to the consumers in question. In this sense, the

explicit valuation of demand response on the capacity mar-

ket complements the new valuation opportunities created by

the NEBEF136 rules, which allow load reductions to be valued

at sites independently of the technological limitations of the

meters used there, based on information provided by demand-

side operators.

4.2.3 Notification of PP1 hours

4.2.3.1 Principles

On first analysis, targeting real peak periods on the power system

would require defining PP1 at the end of the delivery year, based

on the hours of highest demand observed during the winter.

This solution would nonetheless create two types of difficulty:

> “Peak shift”: Demand-side management measures taken by

obligated parties during the hours expected to be the hours

“of highest consumption” could have such a powerful impact

135Indeed, since demand reduction efforts are not factored into the load curve (no localised decrease in consumption), the possibility of efforts being rewarded is diluted in proportion to the consumer's share of profiled consumption (in the short term, through the alignment coefficient used in the BRE process which ensures consistency at each time step of the overall profile consumption result) or its share of consumers with this profile (longer term, through an updating of the profile).

136Block Exchange Notification of Demand Response. See report on the explicit valuation of demand response on the wholesale market on the RTE website.

on demand that these hours would no longer be included in

actual peak hours. This phenomenon could prevent demand-

side management measures from reducing the parties’ obli-

gation, in which case the mechanism’s impact would be dis-

proportionate to its objective;

> Predictability of PP1: A very large number of participants in

the consultation asked to have information about potential

peak periods in advance, in order to activate the measures at

their disposal with greater certainty. This point is of particular

concern to suppliers because the entire cost of the obligation

will be concentrated on PP1 hours.

4.2.3.2 Effect of notification on the selection of

the hours of highest consumption

The ideal signal should enable the selection solely of the hours

of highest consumption. However, it is by nature not possible

to predict the corresponding hours with any certainty: the issue

is exactly the same for market stakeholders as for the system

operator.

Given the link between consumption and temperature, pre-

dicting that demand on any particular day will be among the

highest of the winter comes down to predicting that that day

will be one of the coldest of the winter. It would require visibi-

lity on general temperature trends over a long period, whereas

short-term weather forecasts are not currently usable beyond

ten days. Climate scenarios, particularly those used in supply/

demand balance studies, do indeed provide visibility on the

temperature distribution at a given hour of the day and the year,

but it is not possible to deduce the temperature of a given hour

based on past values.

RTE conducted studies on a notification of PP1 hours based on

hour or day type criteria, to establish whether notification would

decrease the performance in terms of targeting the hours of

highest consumption. The studies confirm that targeting will

To address these difficulties, RTE proposes that the PP1 days that will be used to calculate suppliers’ obligations be notified one day ahead of time.

Notification of PP1 hours with a reduced volume requires managing the stock of hours to be noti-fied. Consequently, the hours notified might not correspond exclusively to the hours of highest consumption during the delivery year as observed after the fact.

85

CAPACITY OBLIGATION / 4

IllustrationoftheconsequencesofthechoiceofPP1foraconsumercapableofreducing

itsconsumptionby50%over15days

For purposes of simplifi cation, it is assumed that the consumer is non-temperature sensitive and that its consumption is constant

(equal to C) over the year in order to illustrate only the consequences of the choice of PP1. The consumer’s reference power thus

corresponds to its average consumption over PP1.

referenceP = Consumptionaverage on PP1 = C – Load reductionPP1

The impact of PP1 on the consumer’s reference power therefore corresponds to the taking into account of load reductions as

a function of PP1.

With a targeted PP1, the load reduction is considered in its entirety and consistently with its contribution to reducing the shortfall

risk:

Load reductiontargetedPP1 = NB activationload reduction x Volumeload reduction = 50%.C

referenceP, targetedPP1 = 50%.C

With a long PP1, to provide maximum benefi t to the consumer through a reduction of its obligation, the load reduction must be

positioned on the month corresponding to the highest weighting. In this illustration and in line with a weighting proposed in the

consultation, this month is January, with a weighting of 70%.

Load reduction long PP1 = Weightjanuary x NB activationload reduction x Volumeload reduction

= 70% x 15 x 50%.C = 21%.C

referenceP,long PP1 = 79%.C

This example illustrates the importance of the choice of the PP1 period for rewarding demand management actions through a

reduction of the obligation. The value assigned to demand response is reduced by more than half with a long PP1 period even

though its contribution to reducing the shortfall risk is virtually equivalent to that of a resource without constraints.

The example also illustrates the impact of a long PP1 period in terms of potential contradictions between incentives in the

energy market and the capacity mechanism. Thus for a delivery year such as 2012 with a cold spell in February, if the consumer

focuses demand response on the hours of the cold spell, this would only be refl ected in its capacity obligation in proportion to

the weighting of February (20% in the weighting presented in the consultation), resulting in an even lower benefi t (6%.C).

NB PP1 days

NB working days

25

86

Analysis of the performance of the signal

Table 1 – Days criterion – Performance in notifying the 100 hours of highest demand.

Nb of Days notifi ed* 10 15 20 25 30 35 40 45 50

Av. Nb Peak Days notifi ed 9.22 13.58 17.44 20.5 22.62 24.18 25.3 26.16 26.68

Min. Nb Peak Days notifi ed 6 9 12 14 16 19 20 20 20

Max. Nb Peak Days notifi ed 10 15 20 25 28 31 33 36 39

Average score 63.98% 79.20% 87.92% 91.34% 93.10% 95.38% 96.40% 97.64% 98.34%

Figure 25 – Distribution of the results of the table above

Table 1 shows that to expect to identify 90% of the

100  hours of highest consumption, it is necessary to

notify between 20 and 25 days (approximately 350

hours). It is important to underline that with a stock of

15 days, in 25% of cases, the signal only enables iden-

tifi cation of at most 70% of the 100 hours of highest

consumption (min. at 25%).

This volume is consistent with the distribution of the

100 hours of highest consumption for each winter – on

average over 20 days between November and March.

Figure 26 – Number of days containing the days of highest demand each winter (Source: Power consumption records – RTE Customer website)

If all the PP1 hours correspond exactly to the notifi ed hours, the period notifi ed must be reduced, in line with the defi nition of

PP1. In this sense, a period of 10 to 15 days (100 to 150 hours) is consistent with the volume necessary to estimate the contribu-

tion to the shortfall risk (see § 4.2.1).

The results of the above study on the signal, summarised in Table 1, show that a signal that covers such a period enables

identification of between 60% and 80% of the 100 hours of highest consumption. However, PP1 does not then solely con-

sist of the hours of highest demand. Of the days notified, on average one day out of 10 or two days out of 15 (for a signal

of 10 notified days or 15 notified days respectively) do not contain any of the 100 hours of highest demand in the winter.

The study showed it is possible that up to 40% of the notified days will contain none of the 100 hours of highest demand

(with 15 days notified).

0%10 15 20 25 30 35 40 45 50

25%

50%

75%

100%

Number of days notified in winter

% o

f th

e 10

0 h

ours

of h

igh

est d

eman

dam

ong

the

hou

rs n

otifi

ed

0

10

20

30

40

50

60

1996199719981999200020012002200320042005200620072008200920102011

1996199719981999200020012002200320042005200620072008200920102011

1996199719981999200020012002200320042005200620072008200920102011

1996199719981999200020012002200320042005200620072008200920102011

1996199719981999200020012002200320042005200620072008200920102011

1996199719981999200020012002200320042005200620072008200920102011

50 H

Ave = 12 d Ave = 20 d Ave = 26 d Ave = 32 d Ave = 38 d Ave = 42 d

100 H 150 H

Winter

Nu

mbe

r of d

ays

200 H 250 H 300 H

* “Peak Day”: Day containing at least one hour of the 100 hours of highest demand

87

CAPACITY OBLIGATION / 4

It is therefore necessary for the choice of PP1 to incorporate

elements allowing the variability of the obligation volume to be

smoothed, and in particular to:

> Remove periods of “interruption”, i.e. periods when demand is

not representative of normal behaviour (weekends, bank holi-

days and Christmas holidays);

> Include periods when temperatures are cold, limiting the

uncertainty linked to errors in the modelling of the climatic

correction;

> Include PP1 days (defi ned time slot) rather than independent

hours in order to stabilise intraday variations in consumption.

Lastly, notifi cation of PP1 days prevents a very high concentra-

tion of PP1 hours over a short period and thus tends to smooth

the distribution of the days notifi ed over the winter period. Using

a signal to designate PP1 days thus helps to stabilise reference

power.

4.2.4 Sensitivity of the obligation to the location in time of PP1

Variations in non-temperature sensitive consumption over the

winter result in a slight variation in reference power depending

on the “location” of the PP1 hours selected. During the consul-

tation, some suppliers cited this infl uence to request that the

PP1 period be extended, in order to stabilise the obligation. As

indicated above, RTE conducted specifi c studies on this issue to

quantify the uncertainty associated with the location in time of

PP1 days. These studies established that the location in time of

PP1 days has little infl uence on the amount of the obligation.

not be perfect, illustrate the impact of the number of days noti-

fi ed on the signal’s accuracy, and show that a PP1 period of

10-15 days will cover most of the hours of highest consumption.

4.2.3.3 Eff ect of PP1 notifi cation on the obligation level

“Transposing” actual consumption to an extreme temperature is

a way to translate the key critical risk facing the power system

and the level of tension against which it seeks to protect itself.

In fi gure 27, the climatic correction translates actual consump-

tion (yellow curve @realisedT) into consumption at the extreme

temperature, which serves as the reference for calculating the

obligation (blue curve @extT). In terms of temperature sensiti-

vity, the choice of the PP1 period, i.e. the choice of the points of

the blue curve, has no eff ect on the volume ultimately obtained.

However, though the extrapolation of temperature sensitive

consumption to the extreme temperature allows the wea-

ther contingency to be isolated, we also observe a variation

in non-temperature sensitive consumption during the winter

(see fi gure 28). Increased use of lighting when days get shorter

explains the bell-shaped variation centred on January (the dip is

due to the Christmas holidays).

This change in non-temperature sensitive consumption during

the winter leads to a variation in the reference power according

to the “location” of the hours of highest demand during the

winter. Thus, a winter in which the hours of highest demand are

in January will show a higher reference power than a winter in

which the hours of highest demand are at the end of February.

Figure 27 – Illustration of climatic correction on an ErDF profi led portfolio (Source: ERDF, WG of 09/07/13)

0

10

20

30

40

50

60

70

80

90

@TE

@TR

November December January February March

Pow

er [G

W]

Clim. Corr.TR TE

88

Figure 28 – Illustration of variations in temperature sensitive and non-temperature sensitive demand in the year 2011-2012 (data: RTE – 2012 Electrical Energy Statistics)

20

40

60

80

100

Sept

.

Oct

.

Nov

.

Dec

.

Jan.

Feb.

Mar

ch

April

May

June July

Aug.

Sept

.

Ave

rage

dai

ly p

ower

(GW

)

Month Average Standard deviation Min. Max.

November 2% 5% 0% 20%

December 22% 24% 0% 70%

January 52% 26% 0% 90%

February 21% 24% 0% 100%

March 2% 10% 0% 40%

Table 2 – Distribution of the ten days of highest consumption since 1996 (Data: RTE Customer website – Power consumption records since 1996)

  Consumption excl. heating

  Demand response

 Heating

 Air conditioning

It should be noted that the hours of highest consumption do

not occur in a random or uniform way over the winter period

as a whole. For instance, the ten days of highest consumption

have never all fallen in November or in March. The December

to February period contains on average 96% of the ten days

of highest consumption and at least 60% of these ten days.

The uncertainty resulting from the location in time of the PP1

days does not therefore correspond to the min-max variation

between the peak in January and the dip at the end of March.

The studies carried out seek to estimate (i) the level of variability

of the France obligation linked to the location in time of PP1,

and (ii) the benefi t of possible PP1 milestones in the last and fi rst

months, March and November.

4.2.4.1 Estimation of the sensitivity of reference power

based on actual consumption

The sensitivity of the France reference power to the selection of

PP1 days, factoring in the eff ect of PP1 day notifi cation, was eva-

luated over several years. For this purpose, consumption levels

transposed to the extreme temperature were calculated for

each eligible day, applying the methods described in the rules,

over the six years from 2006 to 2011.

For each delivery year, the 100 France consumption scenarios

for the year in question, drawn from the 100  Météo France

climate scenarios representative of the existing climate, were

divided into two sets of 50 scenarios: the first (the calibration

set) was used to determine the parameters of the signal and

89

CAPACITY OBLIGATION / 4

Figure 29 – Variability of reference power incorporating the eff ect of PP1 day notifi cation

    Jan. – March & Nov. – Dec. with PP1 notifi cation (MW)

Jan. – March & Nov. – Dec. with PP1 notifi cation (%)

Stan

dard

dev

iati

on (M

W)

Stan

dard

dev

iati

on a

s %

of r

efP

0

200

400

600

800

1000

1200

1400

0

0.2%

0.4%

0.6%

0.8%

1.0%

1.2%

1.4%

2006 2011 Average2010200920082007

the second (the test set) to obtain a distribution of notified

days. This methodology using sets of calibration and test sce-

narios that are consistent yet different makes it possible to

obtain unbiased results (neither overestimated nor underes-

timated). The test set yields 50 distribution scenarios for PP1

days that are consistent with the provisions adopted in the

rules.

The distribution scenarios and consumptions at extreme tempe-

ratures for each delivery year enable 50 reference power values

to be obtained, thus giving a good estimator of the variability of

reference power incorporating the notifi cation.

Two lessons can be drawn from this study, based on the distribu-

tion of the selected PP1 days over the delivery period:

> The average variability over these six years is low, with a stan-

dard deviation of 500 MW, or a variability of less than 0.6% of

the France reference power;

> For each delivery year, the standard deviation is between

400 and 600 MW.

4.2.4.2 Estimation of the benefi ts of milestones in

March and November for the PP1 peak period

During the consultation, certain stakeholders proposed

methods of limiting the eff ect of the variation in non-tempera-

ture sensitive consumption by limiting the number of PP1 days

in the months of March and November or even using only the

months of January, February and December as the period for

selecting PP1 days.

RTE carried out a study based on actual consumption and

Météo France climate scenarios comparing the sensitivity of

reference power to the location in time of the PP1 hours with

(1) a milestone of fi ve days at most introduced in March and

November and (2) only the period [ January; February; Decem-

ber] taken into account. The sensitivity obtained in both cases

was then compared with that obtained with no milestone, which

served as a benchmark (basis 100).

This analysis shows that a limitation of the number of PP1 days

in March and November has no signifi cant eff ect on the variabi-

lity of reference power. Consequently, these methods were not

adopted in the mechanism rules.

Figure 30 – Impact of PP1 milestones on the variability of reference power

Rel

ativ

e se

nsi

tivi

ty o

f ref

P.(b

asis

100

: sta

ndar

d de

viat

ion

ofre

fP w

ithou

t mile

ston

e)

2006 2007 2008 2009 2010 2011 Average

0

20

40

60

80

100

120

140

160

 Jan. to March & Nov. and Dec. with max. 5 d in March and Nov.  Jan and Feb. & Dec.

90

To summarise, the two studies conducted confirm that the

methods adopted in the rules on the PP1 peak period lead to

a reference power, for France, with a low degree of sensitivity

to the actual climate in the delivery year: the average standard

deviation is 500  MW, a value well below the 2  GW threshold

adopted as the maximum imbalance for settlements. Additional

studies focusing on the supplier level support these results, and

can be found in § 4.3.4.

4.2.5 Provisions adopted in the rules on PP1

A series of major expectations regarding PP1 were expressed in

the course of the consultation:

> The hours notified must correspond to the hours when natio-

nal demand is actually highest;

> The hours notified are the PP1 hours (signal creating a

commitment);

> The volume of PP1 corresponds to a reduced number of hours

(50 to 200 hours).

Based on the results of the study on the signal discussed above,

these requirements are incompatible. It is therefore necessary

to ease certain constraints when defining the PP1 period:

> The volume of PP1 is not fixed but varies between a lower

and upper limit. The definition of these limits was conside-

red based on the performance of the signal obtained and

in compliance with the principle of non-discrimination

between reductions of the obligation and certified demand

response;

> The notification of PP1 is based on a consumption criterion.

PP1 hours will therefore be hours of high consumption. Howe-

ver, as the volume of PP1 is regulated and kept targeted, the

PP1 hours will not necessarily systematically be the hours of

highest consumption of the delivery year.

RTE proposes that PP1 days be notified on D-1 at 10:30am.

The need for a notification time prior to fixing on the spot mar-

ket became apparent during the consultation, as this allows

suppliers to activate peak demand management measures to

reduce their obligation and adjust their energy coverage accor-

dingly. Choosing the latest possible time makes it possible to

refine the demand forecast used for the notification and there-

fore to target days of high consumption more accurately.

The demand criterion used for activating a PP1 signal will be based on:

> Statistical distributions of possible consumptions at this

period of the year, produced by RTE on the basis of Météo

France temperature series and medium-term weather fore-

casts. These distributions are used to define consumption

thresholds beyond which a signal is sent;

> The day-ahead national demand forecast drawn up by RTE on

the basis of Météo France short-term temperature forecasts.

The PP1 peak period defined in the rules thus enables the natio-

nal demand peak to be targeted as closely as possible, with a pro-

vision included to provide greater stability for obligated parties.

1. The PP1 period corresponds to the time slots [07:00; 15:00[ and [18:00; 20:00[ (i.e. ten hours per day) on days notified by RTE.

2. The days notified are not selected before the delivery period. However, they will always be working days in the months between Novem-ber and March, minus the period correspon-ding to the Christmas school holidays.

3. PP1 days are notified on D-1 at 10:30am. Notification is based on a demand criterion.

4. The number of PP1 days notified varies between 10 and 15.

4.3.1 Overlapping year centred on a winter or calendar year

The decree stipulates that the delivery year is “a twelve-month

period, not necessarily coinciding with the calendar year, that

includes a PP1 peak period and a PP2 peak period”.

The decree indicates that the first delivery year is to include the

winter of 2016-2017 (“The first delivery year begins in 2016 and

4.3 Delivery year

covers the peak periods of the winter of 2016-2017”) but does

not specify anything for the following years.

The consultation highlighted two possible ways of defining the

delivery year: a delivery year centred on a winter (overlapping two

calendar years) or a delivery year corresponding to a calendar year.

The key arguments made to support either of the two options

were based on:

91

CAPACITY OBLIGATION / 4

> “Physical” factors associated with the actual management of the

power system, supporting a delivery year overlapping two years;

> “Contractual” factors relating to how the capacity mechanism

would fi t into the existing contractual system (energy market

and ARENH mechanism), supporting a delivery year corres-

ponding to a calendar year.

The issue of compliance with the European framework was also

addressed during the consultation: the defi nition of a “capa-

city certifi cate” product with identical periods would facilitate

exchanges of this product between countries.

All of the topics discussed during the consultation and pres-

ented in this section show that, in practice, provisions such as

the notifi cation of PP1 days reduce the impact on suppliers of

the defi nition of the delivery year. RTE therefore proposes that

the mechanism operate according to the calendar year, which

should facilitate its integration with existing contractual prac-

tices and then with Europe going forward.

4.3.2 Impact of the choice of the delivery year on the functioning of the mechanism

A delivery year that corresponds to the calendar year will make

the post-delivery year trading period longer than with a staggered

year; the transfer deadline is closely correlated to the deadline for

gathering defi nitive consumption data (fi nal consumption data

for December of year Y are not known until October Y+2).

The choice of a calendar year including two peak periods

(January to March and November-December) thus makes it

more diffi cult to send a signal on peak periods, as RTE only has

detailed information on the system at a seasonal scale.

4.3.3 Sensitivity of the capacity mechanism to the defi nition of the delivery year with regard to the security of supply objective

Aligning the delivery year with the calendar year leads to two dis-

tinct types of risks because of structural changes in consump-

tion and the capacity mix.

In terms of consumption, choosing a calendar year leads to

variability in the overall level of obligation due to the structural

growth in demand over a year (up to 2%). Nearly a year goes

by between the two winter segments of a calendar year. This

demand trend is structural and the climatic correction applied

does not compensate for the diff erence between the two refe-

rence power levels. Thus, depending on the location of the

PP1 hours, the reference power obtained will correspond to an

Figure 31 – Location of the 200 hours of highest demand of each delivery year with a calendar year and overlapping year

jan. 1996

jan. 1997

jan. 1998

jan. 1999

jan. 2000

jan. 2001

jan. 2002

jan. 2003

jan. 2004

jan. 2005

jan. 2006

jan. 2007

jan. 2008

jan. 2009

jan. 2010

jan. 2011

jan. 2012

jan. 2013

jan. 2014

jan. 1996

jan. 1997

jan. 1998

jan. 1999

jan. 2000

jan. 2001

jan. 2002

jan. 2003

jan. 2004

jan. 2005

jan. 2006

jan. 2007

jan. 2008

jan. 2009

jan. 2010

jan. 2011

jan. 2012

jan. 2013

jan. 2014

30

40

50

60

70

80

90

100

Con

sum

ptio

n (G

W)

Overlapping yearCalendar year

30

40

50

60

70

80

90

100

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

92

average of these two levels, weighted by the distribution of the

PP1 hours between the fi rst and second periods.

To illustrate this point, the consumption curves from 1996

to 2012 are shown with, in colour, the 200  hours of highest

consumption for a calendar year and for a staggered year.

Choosing a calendar year leads to the selection of 200  hours

corresponding to consumptions that underestimate the winter

peak. This eff ect is particularly visible in 2008 (consumption in

purple).

RTE conducted an analysis to evaluate the sensitivity of the

“France” reference power to the type of delivery year chosen.

One hundred PP1 hour distribution scenarios were considered,

obtained from 100 France consumption scenarios drawn from

the 100  Météo France climate scenarios representative of the

existing climate. For each scenario, PP1 hours were chosen

based on provisions of the draft rules (time slots and eligible

days, volume between ten and 15 days, notifi cation based on a

demand criterion).

The analysis shows fi rst of all that the “France” reference power

has a low degree of sensitivity to the distribution of the PP1

hours, whatever the option chosen for the delivery year: the

standard deviation is around 400 to 500 MW, or approximately

0.5% of the “France” reference power. This is in line with the

results presented above.

Secondly, it can be seen that the choice of a calendar year

slightly increases average uncertainty about the overall level of

obligation due to the location of the PP1 hours in time, for all the

years studied apart from 2008. The average standard deviation

is 490 MW (0.55% of the average “France” reference power) with

a calendar year compared with 450  MW (0.5% of the average

“France” reference power) with a staggered year.

4.3.4 Sensitivity of suppliers’ obligation to the choice of delivery year

Current commercial practices, at least in the large consumers

market, are organised around annual contractual periods begin-

ning on 1 January of each year of the contracts. This can result in

a signifi cant change in the customer portfolio of a given supplier

on 1 January. The actual distribution of the PP1 hours between

the periods before and after 1 January therefore plays a decisive

role as regards the amount of a supplier’s obligation.

To estimate the sensitivity of the reference power of the main

suppliers to the option chosen for the delivery year, RTE conduc-

ted a study using the same methodology as above but this time

at the supplier level.

Figure 33 summarises the results obtained for the main Balance

Responsible Parties (BRPs) (reference power of more than

800 MW). It represents, for the six years considered, the average

variability of the obligation of each BRP in proportion to its refe-

rence power, depending on whether the delivery year is centred

on a winter or corresponds to a calendar year.

The analysis shows that the standard deviation is less than 4%

for all the main suppliers, and even below 2% for all except one.

Comparing this with the initial simulation results presented in the

interim report of September 2013, we can note that the variabi-

lity of the reference power of the main suppliers is considerably

Figure 32 – Relative uncertainty linked to the choice of the delivery year on France reference power

Figure 33 – Relative uncertainty linked to the choice of the delivery year on the reference power of the main BRPs

Stan

dard

dev

iati

on (M

W)

Stan

dard

dev

iati

on a

s %

of r

efP

0

100

200

300

400

500

600

700

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

2006 2011 Average2010200920082007

Stan

dard

dev

iati

on a

s %

of r

efP

Main BRPs0%

1%

2%

3%

4%

5%

 Winter year – Absolute deviation (MW)  Calendar year – Absolute deviation (MW)

 Winter year – Relative deviation (%)  Calendar year – Relative deviation (%)

 Winter year  Calendar year

93

CAPACITY OBLIGATION / 4

lower. This refl ects the notifi cation of PP1 days, which results in

the days being distributed over the delivery period and, ultima-

tely, to a regulation of the weight of the early winter (November

and December)137. Consequently, the variability of reference

power due to the change in portfolios on 1 January is smoothed.

However, variability in the obligation is still greater for several sup-

pliers with a staggered year than with a calendar year (average dif-

ference in variability of more than 1 to 2 percentage points), espe-

cially as their contractual practice is centred on a calendar year.

Taking this observation as a starting point, several approaches

are possible.

The fi rst consists in introducing parameters in the capacity

mechanism rules to reduce the sensitivity of suppliers’ obliga-

tion to the location of the PP1 hours, either by:

> Stipulating a breakdown of PP1 hours between the periods

before and after 1 January: this option necessarily diminishes

the quality of the signal. Based on the same number of days,

hours with lower demand would be selected than with a sys-

tem with no predefi ned distribution. Insofar as peaks would

be less accurately targeted, issues relating to the valuation of

non-certifi ed demand response and the increase in the tem-

perature sensitivity modelling error would be exacerbated. To

address these problems, an increase in the number of PP1

days would enable the hours of highest consumption to be

better targeted, despite the predefi ned distribution, but would

also dilute the value of peak demand response;

> Aligning delivery years with calendar years: this

solution leads to a slightly higher variability of the

overall level of obligation but is very eff ective in

terms of stabilisation.

The second approach consists in transferring res-

ponsibility for managing this risk to suppliers, which

can if necessary cover it with initiatives outside the

capacity mechanism. Suppliers could implement

various solutions to manage and cover this risk:

> Contracts with consumers: one practical way would be to

make contract durations match the delivery years of the capa-

city mechanism;

> Hedging instruments: the risk stemming from the location

of PP1 hours essentially corresponds to the distribution of

reference power between suppliers, as the total reference

power is aff ected only to a small degree. In theory, suppliers

are therefore justifi ed in entering into hedging arrangements

amongst themselves to protect themselves against this. The

cost of hedging this risk should theoretically be low, apart

from interface costs, since the overall risk is low and one of

distribution. Such hedging products do not currently exist and

would therefore have to be created;

> Trading of certifi cates during the delivery period or beyond:

again, the choice of the delivery year essentially creates a risk

relating to the distribution of reference power between sup-

pliers. The decree allows for transfers of capacity certifi cates

during the delivery year and even after obligated parties have

been notifi ed of their obligation. Consequently, it is possible

137In the studies conducted by RTE on historical data, November and December account on average for 40% of PP1 days with a standard deviation of around 10%. These values are very stable from one delivery year to the next.

Figure 34 – Relative uncertainty associated with choice of delivery year on residual obligation of the main BRPs considering an allocation of ARENH rights in proportion to PP1 days

Main BRPs

Stan

dard

dev

iati

on a

s %

of r

efP

0

1

2

3

4

5

 Winter year  Calendar year

94

for suppliers to adjust their coverage based on the actual loca-

tion in time of PP1 hours by trading certificates.

During the consultation, many suppliers also stressed that the

methodology that will be used to allocate the capacity cer-

tificates associated with ARENH rights was not known when

the draft rules were submitted for consultation. The allocation

method chosen for ARENH certificates can have conside-

rable effects on the variability of suppliers’ reference power.

Basically, if the amount of ARENH certificates allocated to

suppliers changes symmetrically with their reference power

depending on the distribution of PP1 days, then suppliers are

exposed only on the residual consumption volume excluding

ARENH.

To estimate the possible effects of the allocation of ARENH certi-

ficates, the same sensitivity analysis was carried out considering

the residual obligation of suppliers once the ARENH certificates

have been allocated. In the model used, ARENH certificates are

allocated in proportion to the number of PP1 hours and ARENH

rights for the year N and N+1.

With the method of allocating ARENH certificates adopted for

this study, the variability of the residual obligation of all the main

suppliers apart from one is lower with a staggered year than with

a calendar year.

These results therefore show that the option chosen for allo-

cating the capacity certificates associated with ARENH rights

can limit the impact of the location of the PP1 hours linked to

the change in customer portfolios on 1 January. Thus, depen-

ding on the methods chosen for the ARENH, the option of an

overlapping year for the capacity mechanism could be adop-

ted without necessarily requiring a re-adaptation of current

commercial practices in the energy industry based on calen-

dar years.

Provision adopted in the rules for the delivery year

The studies conducted on the choice of the year do not identify one type of delivery year that stands out clearly intermsofstabilityalone. The sensitivity of the obligation to the choice of the delivery year is relatively low both for France and at supplier level, notably because notification distributes the days over the whole delivery period. These studies are all the less conclusive because the methods of allocating capacity certificates to ARENH rights are not known and can greatly affect the variability of suppliers’ obligations.

The debate about the type of delivery year to be selected is actually about a choice between two approaches: one based on the physical management of the system, which favours a staggered year centred on a winter, and one based on contracts, which favours a calendar year since this is usually the basis for contracts in the energy market.

Therulesproposeadeliveryyearmatchingthecalendaryear,startingwiththesecondyearthemechanismisinplace. This is the preferred choice of alternative suppliers and industrial consumers, since it will allow the capacity mechanism to align with existing contractual practices in the energy market.

At a time when the European Commission is asking Member States to align their approaches to capacity questions with the broader framework of the European energy market, the choice of a calendar year should also facilitate subsequent integration at the European level, based on existing contractual practices.

In keeping with the provisions of the decree and to facilitate the transition to the calendar year targeted, the first delivery year will begin on 1 November 2016 and end on 31 December 2017, with July and August 2017 excluded.

4.4.1 Determination of the obligation parameters (extreme temperature and security factor)

4.4.1.1 Timing of the publication of obligation parameters

Article 18 of the decree stipulates that “during the four-year

period preceding each delivery year, and at least once a year

for each delivery year, the public electricity transmission system

4.4 Parameters of the capacity obligation

operator publishes forecasts relating to the overall level of

capacity certificates enabling the capacity obligation of all sup-

pliers to be met.” This publication is based on a supply-demand

balance study conducted for the delivery year.

The rules include a provision that corresponds to the use of this

adequacy study to determine the possible need for an updating

95

CAPACITY OBLIGATION / 4

of the obligation parameters (extreme temperature and secu-

rity factor) and of the tables used for capacity certification (see

§ 5.3.2).

Any updates to these parameters must be approved by the

Energy Minister. Indeed, in the absence of specific references

in the decree to changes made to provisions in the rules, the

principle of parallel powers gives the authority responsible for

enacting an act the power to amend or abolish it. In this ins-

tance, insofar as the Minister approves “all provisions relating

to capacity certification” and “all provisions relating to capacity

obligation, and in particular to the method of calculating refe-

rence power and determining suppliers’ obligations”, it must

approve any modification of these parameters.

At the start of a capacity mechanism term, the mechanism para-

meters are published together with the first forecast of the overall

level of certificates. Forecasts of the overall level of certificates are

thus calculated with the same methods and parameters as those

ultimately used for calculating the obligations of obligated parties.

The provision adopted in the rules corresponds to the choice of

stable parameters throughout a term (intra-term stability). Para-

meters may vary from one term to another (inter-term change)

to reflect how the power system evolves and its dynamics over

several years.

Defining the mechanism parameters in advance gives suppliers the

visibility they need to incorporate the impact of the amount of their

obligation into their contracts with customers, meet their obligation

and possibly implement demand management measures.

This system allows compliance with the provisions of the Energy

Code138 stipulating that suppliers must act in advance:

“The obligations imposed on suppliers are determined in such

a way as to encourage compliance in the medium term with

the level of security of supply.”

“Capacity certificates are required sufficiently in advance.”

4.4.1.2 Determination of the reference mix taking the

supply security criterion into account

The obligation parameters are determined based on a supply-

demand balance study for the delivery year.

Through this study, a reference mix is determined that corres-

ponds to the anticipated mix to or from which capacities will be

added or subtracted to obtain a shortfall duration that exactly

matches the supply security criterion defined by

public authorities139, without exceeding it (this

would lead to overcapacity that would be costly

for consumers) or coming in below it (this would

reduce the level of security, at the expense of the

community).

This reference mix is used to estimate the overall

level of obligation corresponding to the volume of

certificates that must be held by the community of

suppliers for the security criterion to be met. The overall level

of obligation corresponds exactly to the volume of certificates

allocated to the reference mix.

3 h criterion met <=> CertificatesOverall Level = ∑ Certificates allocated

This approach ensures the necessary coherence between certi-

fication and obligation: when public authorities’ security of sup-

ply criterion is met, the overall level of certificates (and there-

fore the mix underlying it) exactly matches the sum of suppliers’

obligations.

The amount of certificates allocated to the reference mix is cal-

culated by certifying that mix in accordance with the capacity

mechanism rules for the term in question, i.e. taking into account

any updates to the certification parameters. Consequently, the

certification of the reference mix incorporates all changes in the

power system in its measurement of the contribution of capaci-

ties to reducing the shortfall risk.

138Article L-335.2

139The same method is used here as in the studies in the Adequacy Forecast Report. For further details, see page 35 of the 2013 Adequacy Forecast Report update and pages 82-83 of the 2012 Adequacy Forecast Report.

Figure 35 – Illustration of how the reference mix is determined

Forecast situation

(if E > criterion) (if E < criterion)

Referencemix

Existing capacities

Capacities under construction

Additionalpower Margin

Contribution of interconnections

Shortfall expectation

3h/year

Shortfallexpectation

Xh/year

Reference Mix

96

These two objectives are met thanks to supply-demand balance

studies conducted by RTE. The process involves two stages:

> First, determining the individual contribution to the shortfall risk

which leads to the determination of the extreme temperature;

> Second, ensuring via the security factor that the

mechanism is sufficiently complete to meet the

security of supply criterion.

4.4.2 Extreme temperature

4.4.2.1 Determination of the extreme

temperature

As indicated above, the extreme temperature must be

defined in such a way as to avoid assigning part of the

temperature sensitivity risk to non-temperature sen-

sitive consumers via the security factor. Making tem-

perature sensitive consumers responsible in this way,

without pooling, gives them a considerable incentive

to keep their consumption in check and supports the

peak demand management objective. This assign-

ment of responsibility must therefore be ensured.

Securityfactor

Extreme temp.(> France consumption

at extreme temp.)

Volume ofcertificatesrequired to

meet criterion

Probabilisticsupply-demandbalance study

Reference mix enabling security of

supply criterion to be met

Francesupply and

demandassumptions

Europesupply and

demand assumptions Capacity

certificationparameters

Update based on

changesin system

4.4.1.3 Determination of the obligation parameters

(extreme temperature and security factor)

Certifying the reference mix makes it possible to determine

the total amount of certificates necessary for the supply

security criterion to be met. The parameters of the obligation

(extreme temperature and security factor) are defined in such

a way as to:

> Ensure that the overall obligation volume corresponds exactly

to the volume of certificates of the reference mix, enabling

compliance with the supply security criterion;

> Determine the pair of values [extTsecurityF] that assigns the tem-

perature sensitivity risk to temperature sensitive consumers

without transferring it to non-temperature sensitive consu-

mers (see § 4.1.3.2).

140The power system is transposed to “3 hours” with the same methodology as that used to determine the reference mix (see figure 37).

141A “perfect resource” corresponds to a fictional capacity that is perfectly available with no technical constraint. It serves as a touchstone for the mechanism because each MW from a perfect resource is allocated 1 MW of capacity certificates.

142Considering this demand in France alone would naturally lead to a perfect resource need of 1 MW for 1 MW of consumption.

Figure 36 – Illustration of the relationship between the overall level of certificates and the obligation parameters

Simulations were carried out to determine the extreme tempe-

rature that meets these requirements. A marginal approach was

adopted to allow for the estimation of specific individual para-

meters without disrupting the system as a whole. This is impor-

tant because the phenomena studied intrinsically depend on

the system in which they play out: a consumer’s contribution to

the shortfall risk is directly linked to the form of the shortfall and

therefore to the underlying system as a whole. This approach

thus complies with the letter and spirit of the capacity mecha-

nism decree, which assigns to each consumer its contribution

to the shortfall risk.

The approach used can be described as follows:

> The initial situation corresponds to the projected state of the

interconnected French power system, with security of supply

set at the criterion defined by public authorities;

> Starting from this situation, various consumption profiles are

added marginally, causing security of supply to deviate from

the criterion defined by public authorities140;

> “Perfect resources”141 are then added until security of supply

is restored to the criterion defined by public authorities.

97

CAPACITY OBLIGATION / 4

This approach allows the following results to be obtained:

> The need in terms of perfect resources necessary with

consumption that is constant over the year and perfectly non-

temperature sensitive, taking account of the interconnection

of the French system142, is estimated;

> The addition of a purely temperature sensitive consumer

(perfect linearity of behaviour, no non-temperature sensitive

consumption and therefore no consumption at temperatures

above 15°C) then allows the calculation of the extreme tem-

perature taking account of interconnections. The addition of

such a consumer with a gradient of 100 MW/°C reveals a per-

fect resource need that corresponds to its consumption for a

temperature of -2.6°C in the interconnected French system.

The marginal approach is an eff ective way to separate the contri-

butions to the shortfall risk of non-temperature sensitive and

temperature sensitive users’ consumptions and to refl ect them,

without transfer, in the parameters of the capacity obligation.

4.4.2.2 Illustration of the extreme temperature with

regard to the weather contingency to which the system

is subject

To take into account temperature variations within a day, the

provisions adopted in the rules correspond to the choice of

a daily extreme temperature series in half-hourly steps. The

extreme temperature therefore takes the form of a vector with

20  values corresponding to the extreme temperatures of the

20  half-hourly steps of the PP1 range. The half-hourly transla-

tion of the extreme temperature adopted in the rules links the

extreme temperature, a result of supply-demand balance simu-

lations, with the climate data representative of all possible situa-

tions in the current climate.

A study was conducted on the basis of Météo France climate

data currently in force, consisting of 100  temperature series

representative of the current climate. Figure 38 corresponds to

temperatures constructed with the methodology described in

the rules.

Figure 37 – Illustration of the marginal approach to determining the contribution of a consumption profi le to the shortfall risk

Value of adequacycriterion = K

0 (3h)

Value of adequacycriterion = K

1

Addition of specificconsumption profile

Addition of X MW froma perfect resource

Value of adequacycriterion = K

2

By iteration, wedetermine X such that

K2 = K0 (back to 3h)

1

2

Figure 38 – Illustration of the extreme temperature with regard to the weather contingency

Smoo

thed

tem

pera

ture

(°C

)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

-6

-5

-4

-3

-2

-1

0

08/02/12 1/20 1/10 1/5

98

Hourly extreme temperatures corresponding to a given level of

risk (1-in-20  chance, 1-in-10  chance and 1-in-5 chance) were

determined from these data. They correspond, for each hourly

step, to the quantile with the lowest temperatures of each series.

Thus the temperature with a 1-in-10  chance corresponds to

the 10th percentile of the minimum values of each series, and

the temperature with a 1-in-20 chance corresponds to the 5th

percentile of the minimum temperatures.

Figure 38 represents the extreme temperatures obtained with

the three abovementioned levels of risks and the coldest day of

the cold spell in February 2012.

Given the importance of temperature risk in the French power

system, its statistical distribution and its time constant of

approximately one week (see figure 39), the three hours of

expected shortfall in the French power system translate into a

shortfall that appears on average for 30 hours every ten years,

when an exceptional cold spell occurs. The mechanism there-

fore aims to act as if a severe cold spell occurred each year.

At supplier level, this comes down to making suppliers’ level of

obligation insensitive to the actual occurrence of the weather

contingency and transposing observed consumption to the

extreme temperature representative of the temperature sensi-

tivity risk.

4.4.3 Security factor

4.4.3.1 Taking interconnections into account in the

security factor

The law stipulates that the obligation takes into account the

interconnection of the French market with the other European

markets. The decree specifies that the security factor takes

account of the contribution of interconnections. Concretely,

“implicit” recognition of the contribution leads to a reduction of

suppliers’ obligation in proportion to the contribution of inter-

connections to security of supply.

The methodology applied to take the contribution of intercon-

nections to security of supply in France into account is drawn

from that used by RTE for adequacy studies (Adequacy Forecast

Reports): the role of interconnections is taken into account in

supply-demand balance studies through detailed modelling of

the whole of Western Europe.

The contribution of interconnections is thus accounted for

“implicitly”, through decisions about the size of the reference

Figure 39 – Cold spells in France – From 1947 to 2012(Source: Météo France)

The above studies show that the reference extreme temperature that is meaningful for determining the capacity obligation is represen-tative of one-in-ten-year cold conditions.

12 to 19 January1966

30 January to 7 February 1954

6 to 13 January2003

22 to 31 January1947

5 to 14 February1991

14 to 24 December1963

14 au 24 December2001

26 December 1996to 8 January 1997

8 to 23 January1987 1 to 27 February

1956

12 January to 6 February 1963

3 to 17 January1985

23 December 1970to 6 January 1971

1 to 13 February2012

7 to 13 February1986

23 to 28December 1962

19 to 24 February1948

7 to 11 January1967

16 to 21 January1957

10 to 17 January1960

4 to 8 March 1971

-12

-10

-8

-6

-4

-2

0

0 5 10 15 20 25 30 35

Min

imu

m v

alu

e of

tem

pera

ture

indi

cato

r (°C

)

Duration (number of days)The diameter of the spheres symbolises the overall intensity of cold spells, the biggest spheres corresponding to the most severe.

99

CAPACITY OBLIGATION / 4

Figure 40 – European modelling of supply-demand balance studies

Extensive modelling ofthe whole of Western Europe

Consumption

Availabilityof generation

Renewableenergies

Hydropower

Reference mix

Stochastic simulation(1,000 years simulated)

Stock managementInterconnections

Hourly optimisation

mix in France. Basically, if the contribution of interconnections

is nil, all of the power necessary to meet the supply security cri-

terion must be located in France; conversely, if interconnections

can contribute, less capacity is required in France.

The contribution of interconnections depends on two factors:

> The sizing of physical interconnection and its availability;

> The availability of margins in neighbouring countries, i.e.

capacity available beyond what is needed to meet demand in

neighbouring countries.

Indeed, if no margins are available in neighbouring countries,

physical interconnections may be available without any electri-

city being imported. The availability of foreign capacity depends

on factors external to France.

4.4.3.2 Determination of the security factor

The security factor is determined several years in advance and

ensures that the obligation level corresponds to the security of

supply criterion defined by public authorities.

It is set at the start of a capacity mechanism term on the basis of a

supply-demand balance study and is stable throughout the term.

To estimate the value of the security factor, an analysis was car-

ried out on the basis of the study of the year 2017 in the 2012

Adequacy Forecast Report. Figure 41 illustrates the principle for

determining the factor based on this study. This approach was

presented as part of the consultation in June 2013.

The reference generation mix, consisting of existing

capacities and projects under way, adding or remo-

ving “perfect” resources to allow the three-hour loss

of load expectation used as the adequacy criterion to

been met, was certified using the hypotheses for the

modelling of the mix and the outputs of the model:

> On the basis of availability during the 200 hours

of highest demand for thermal units and demand

response;

> On the basis of generation during shortfalls in the model out-

puts for hydropower units.

For 2017, the total volume of certificates enabling the criterion

obtained to be met is thus estimated at 93 GW. This represents

the overall level of certificates that covers the risk represented

via the reference extreme temperature. This volume of certifi-

cates already includes the contribution of interconnections

because foreign countries are explicitly modelled in the study143.

Based on the 100 demand series (1 series = 8,760 hourly ave-

rage power values) that serve as input for the model, and cor-

respond to the 100  climate series provided by Météo France,

an average reference power for France can be estimated. For

each series, the 100  hours of highest consumption are extra-

polated to the extreme temperature, and then the average of

these 100 extrapolated values is calculated. A reference power is

thus obtained for each series. The average of the 100 reference

powers calculated gives an estimate of the France reference

power. It is estimated at 99.7 GW in this study.

143If the study was conducted for France alone, the quantity of additional power required to meet the criterion would be much higher. This quantity represents the contribution of interconnections.

100

Interconnections

taken into account

Intermittence taken

into account

Overalllevel of

certificates

(enablescriterion

to be met)

93 GW

refP_France

(FRconsumptio

at ref T°)

99.7 GW

Overalllevel of

certificates

93 GW

Sum ofcapacity

obligations

93 GW

refP_France

99.7 GW

x secuF = 0.93

securityF

If the three-hour criterion is met, the total obligation must be

equal to the volume of certifi cates of the reference mix. The

security factor ensures consistency between the reference

power and the volume of certifi cates enabling the three-hour

criterion to be met, transferring to the obligation side the contri-

bution of interconnections taken into account in the certifi cation

of the reference mix. The security factor is thus deduced from

the over all level of certifi cates and the France reference power:

∑ Certifi cates = secuF x refP(extT)

=> secuF = 93/99,7 = 0,93

Figure 41 – The taking into account of interconnections and determination of the security factor

4.5 Determination of the obligation

As discussed above, a supplier’s obligation is given by the fol-

lowing formula:

Oblig,DY,OP = refP,DY,OP x SF,DY

> Oblig,DY,OP is the obligation of the obligated party OP for

delivery year DY

> refP,DY,OP is the reference power of the obligated party OP

for delivery year DY

> SF,DY is the security factor for delivery year DY

Si ∑tEPP1 ObservedConsump.OP,DY[t] = 0 alors refP, DY, OP est mise

à 0.

> GradientOP,DY[t] is the gradient of the obligated party OP in

half-hourly step t in delivery year DY;

> AdjustedConsumpOP,DY[t] is the observed consumption of the

obligated party OP, in half-hourly step t in delivery year DY,

adjusting for the demand response capacity activated;

> ExtT [t] is the extreme temperature, in half-hourly step t, for

delivery year DY;

> SFTt, DY[t] is the smoothed and thresholded France tempera-

ture in half-hourly step t in delivery year DY;

> nbHoursPP1,DY is the number of hours of the PP1 peak

period for delivery year DY.

The next section describes in detail how each of these terms,

which are used to determine the obligation, is evaluated, and

thus off ers a very specifi c reading guide for the rules.

4.5.1 Perimeter of an obligated party

4.5.1.1 Definition of the perimeter of an obligated

party

Determining the obligation of an obligated party requires iden-

tifying the consumption covered by this obligated party. For this

refP,DY,OP =1

2 x nbHoursPP1,DYx ∑ [AdjustedConsumpOP,DY[t] + GradientOP,DY[t]

x (ExtT [t] – SFTt,DY[t])]tEPP1

referencemix

101

CAPACITY OBLIGATION / 4

purpose, the concept of the perimeter of an obligated party has

been introduced in the rules.

The perimeter of an obligated party is the reference used to

calculate its reference power. In practice, this perimeter is divi-

ded into sub-perimeters per system operator, grouping the sites

connected to their systems. Procedures for exchanging infor-

mation about and tracking these sub-perimeters are defined in

agreements between distribution system operators and RTE.

The perimeter of an obligated party is not linked to a delivery

year. It has an initial form that evolves in accordance with

changes in the customer portfolio.

The perimeter of an obligated party (Perimeter OP(h, m, DY))

consists of all the sites for which the obligated party bears the

capacity obligation (in whole or in part) in hour h of month m in

delivery year DY.

Each system operator is responsible for monitoring the sub-

perimeter of the obligated parties for which it must calculate

the reference power.

4.5.1.2 Determination of the consumption site-

obligated party link

Consumption levels per obligated party are reconstituted by

allocating the observed consumption of a given consumer

between (a) the supplier(s) for the share they supply and (b) the

consumer itself for the share not sourced from a supplier.

For sites with only one contract, changes occur in the perimeter

with the effective dates of the single contract. The consumer that

holds only one contract and its supplier do not have to take any

special steps to be included in the perimeter of an obligated party.

For sites not bound by a single contract, a consumer is added

to the perimeter of an obligated party based on an attestation

filed jointly by the obligated party and the site. If no attestation

is filed to include a site within a supplier’s perimeter, it is consi-

dered that the site is not supplied by a supplier. In this case it

is directly subject to the capacity obligation and integrated into

the perimeter of the obligated consumer (or one is created, if

the consumer did not register as an obligated party).

The rules therefore adopt a declarative method for the monito-

ring of perimeters, to avoid complex and intrusive monitoring

of all the contractual links between a consumer and its sup-

plier or suppliers. This method enables intrinsic verification of

the attestation, the two parties to the system having opposing

interests: the supplier could seek to minimise its perimeter to

reduce its obligation; conversely, a consumer that does not have

an attestation would find itself bearing the financial burden of

the capacity obligation.

4.5.1.3 Role of public electricity distribution system

operators (DSOs)

DSOs communicate to RTE the reference power for each obliga-

ted party on their system, i.e.:

> The reference power of end consumers connected to their

system per obligated party (supplier and end consumer not

supplied for all or part of its consumption by a supplier) toge-

ther with the data and parameters used;

> The reference power, for their losses, per obligated party (sup-

plier or system operator for its losses not supplied for all or

part of its consumption by a supplier) together with the data

and parameters used.

The reference power per obligated party communicated by each

DSO is calculated in accordance with the provisions of the rules.

This information must be communicated within the deadlines

stipulated in the rules and the exchange agreement between

TSO and DSO for the calculation of the obligation.

4.5.2 Observed consumption

4.5.2.1 Data used

The basic data used to calculate the observed consumption of a

consumer are obtained from the metering and information sys-

tems of the operators of the public systems to which the sites

are connected directly or indirectly.

4.5.2.2 Observed consumption for profiled consumers

For profiled consumption, load curves are established in accor-

dance with the methods defined by the BRP/BM rules in force.

In this respect, the observed consumption data used in the capa-

city mechanism correspond to the Recotemp final consumption

data (aligned and standardised load curve adjusted for activa-

tion of NEBEF), i.e. to the load curve considered to have been

consumed on the basis of meter readings, adjusted for load

reductions.

This load curve, established according to the methods defined

in the BRP/BM rules and the experimental rules for rewarding

demand response on energy markets in force at the beginning

102

of the delivery year, is definitive, unlike the load curves estima-

ted to calculate imbalances, which are not based on actually

measured power levels.

4.5.2.3 Taking into account Site BRP NEBs

4.5.2.3.1 Affiliation with an obligated party 

From a contractual standpoint, the NEB BRP-Site is similar to a

supply contract between the supplier affiliated with the BRP that

issued it and the consumer at the site to which it applies.

The NEB BRP-Site can also be seen as a self-supply vehicle for a

consumer, outside the “conventional” supply contract.

Given the ambiguous nature of the NEB BRP-Site, RTE has

included a flexible proposal in the rules:

> The NEB BRP-Site is affiliated, by default, with the supplier that

issued it;

> The NEB BRP-Site may be assigned to an obligated consumer

that so requests (the request form must be signed by the sup-

plier and consumer).

A request form is attached to the mechanism rules, and

the rules governing NEBs will evolve to ensure that sup-

pliers to all NEB BRP-Sites are identified when notice is

given to RTE.

4.5.2.3.2 Taking the NEB BRP-Site into account 

in calculating the obligation 

Once the NEB BRP-Site is affiliated with an obligated party, the

NEB is included in the obligated party’s adjusted consumption,

but not in the series used for the calculation of its gradient.

In other words, with this provision, NEB BRP-Sites are considered

to be non-temperature sensitive.

4.5.3 Sensitivity of consumption to temperature

4.5.3.1 Smoothed temperature

The process used to construct the smoothed temperature and

choose the threshold temperature adopted in the rules was the

same as that used to factor the weather contingency into the

profiling system.

This choice presents the advantage of using an existing process

that is known to market stakeholders and consistent with cur-

rent processes, particularly the profiling system.

The temperature considered corresponds to the national tem-

perature index calculated for France. It is calculated on the basis

of the Météo France “basket” of 32 weather stations.

The temperatures used correspond to variables derived from the

raw temperature measured at various weather stations. Indeed,

it is is necessary to take into account the inertia of consumption

with respect to temperature variations. This is accomplished by a

“smoothing” of temperatures aimed at delaying and attenuating

temperature variation ranges in order to constitute an effective

explanatory variable of consumption.

A list of the chosen weather stations, the associated weightings

and the smoothing parameters for calculation of the index are

indicated in part IV of Appendix F-M3 of chapter F of section 2

relating to the Balance Responsible Party system. Appendix 2 of

the rules describes the method of smoothing and constructing

the smoothed France temperature.

This smoothed temperature is not used by RTE in its work (Ade-

quacy Forecast Report – climatic corrections). However, the dif-

ferences associated with the temperature variable options used

are minimal.

4.5.3.2 Threshold temperature

The threshold temperature is that indicated in part III of Appen-

dix F-M3 of chapter F of section 2 relating to the Balance Res-

ponsible Party system, namely 15°C at present. The same logic

is applied as in the above section.

4.5.3.3 Gradient

4.5.3.3.1  Estimation of the France gradient and 

gradient per major category of consumption

4.5.3.3.1.1 Method of estimating the gradient

This section presents the method of estimating the gradient adop-

ted on a national level and for each major category of consumption

(all profiled consumers and all remotely metered consumers).

4.5.3.3.1.1.1 General description of the method

An estimation of the gradient by a linear regression of the power

over the temperature cannot be satisfactory because of the sea-

sonal nature of consumption; this needs to be dispensed with

before evaluating the temperature sensitive share.

The methodology adopted in the rules leads to the determina-

tion of half-hourly gradients valid for a delivery year:

103

CAPACITY OBLIGATION / 4

> The gradient is calculated by the “difference regression”

method, i.e. a linear affine regression on the power deviation

with respect to the temperature deviation from one week to

the next. This method avoids the difficulty associated with

estimating the seasonal change in consumption that is not

representative of the temperature sensitivity of consumption;

> The data used pertain to consumption during the delivery

year with the exception of bank holidays and the period cor-

responding to the winter holidays together with the period

either side of them (basically from 01/01 to 12/01 and from

14/12 to 31/12 of the delivery year)144;

> The temperatures are aligned with a threshold temperature

beyond which consumption becomes temperature sensitive.

For this reason, power differences corresponding to nil tempe-

rature differences are omitted145. The gradient is therefore cal-

culated de facto on the cold part of the delivery year.

The singleness and additivity of the method are major assets

for the mechanism. Applied on a set of consistent data

with scaling to consumption in France, it ensures additivity

between the various estimated temperature sensitivities and

the equality of the sum obtained with the temperature sen-

sitivity for France.

Moreover, because consumption data from the delivery year is

used, the values obtained correspond exactly to real tempera-

ture sensitivity.

4.5.3.3.1.1.2 Calculation of the power difference

The power variation is calculated for the same half hour on two

days, one week apart. The weekly variation in seasonality due to

lighting in particular is negligible.

4.5.3.3.1.1.3 Calculation of the temperature difference

As for the power variation, the temperature variation is calculated

for the same half hour on the same two days one week apart.

In accordance with the description of the behaviour of demand

and the temperature sensitivity effect, each temperature is

compared with the threshold temperature in order to use only

the portion that genuinely explains the power difference in the

calculation of the difference. For example, the variation in power

between a half hour at 22°C and a half hour one week later at

17°C is not explained by this difference of 5°C (heating is not

switched on at such temperatures); each temperature is thus

aligned with the threshold temperature, in this case 15°C (min.

function(threshold temperature; actual temperature)), resulting

in a temperature difference of 0°C.

4.5.3.3.1.2 Performance of the method at

nationwide level in France

The method proposed in the draft rules and adop-

ted in the rules for determining load curves in

France, for profiled and remotely metered PDS

consumers, is simple and transparent; it is not based

on obscure black box modelling, and all data used

are public. In this sense, the method chosen for the

capacity mechanism puts all stakeholders on an

equal footing.

During the consultation, however, some stakeholders questio-

ned the performance of this method, notably with regard to two

aspects:

> The simplicity of the method was said to be liable to lead to

results not representative of physical reality;

> Consequently, the evolution of the gradients from one year to

the next was said to be unstable.

RTE carried out a series of studies on the basis of actual

consumption from 2006 to 2012. Based on these analyses,

questions about the method of determining the France gradient

were not taken into account.

4.5.3.3.1.2.1 Representativeness of the results obtained for France

The provisions adopted in the rules concerning the selection of

the pairs of values [consumption; temperature] used to calcu-

late the gradient lead, for each half-hourly step, to scatter plots

consisting of at least 180 points. From a statistical point of view,

the representativeness of the gradients obtained is real.

A study was conducted to estimate the sensitivity of the method

to the observed data used. For this purpose, 1,000 simulations

were carried out during which points used to determine the gra-

dients for a same year and same half-hourly step were randomly

removed. Two different quantities of removals were considered:

20 points and 100 points, or approximately 10% and 50% of the

total number of points used for the calculation.

The results of this study show that:

> The average of the gradients obtained is very stable: the devia-

tion of the average gradient from the initial gradient calcula-

ted with all the points is 0.05% with 20 points removed and

0.2% with 100 points removed;

> The variability of the gradients obtained is low: the standard

deviation is 20 MW, or 1% of the gradient, with 20 points remo-

ved, and 65 MW, or 3% of the gradient, with 100 points removed.

144A long period must be chosen – not just PP1 hours – to ensure that the gradient obtained is sufficiently statistically valid.

145A temperature delta calculated as follows is used:

104

7

9

11

13

15

17

00:0

0:00

01:0

0:00

02:0

0:00

03:0

0:00

04:0

0:00

05:0

0:00

06:0

0:00

07:0

0:00

08:0

0:00

09:0

0:00

10:0

0:00

11:0

0:00

12:0

0:00

13:0

0:00

14:0

0:00

15:0

0:00

16:0

0:00

17:0

0:00

18:0

0:00

19:0

0:00

20:0

0:00

21:0

0:00

22:0

0:00

23:0

0:00

28 March 2012

04 April 2012

21 March 2012

Threshold temp.

CASE 3CASE 2CASE 1

Smoo

thed

tem

pera

ture

[°C

]

min(dT

;

tT) =

dT

min(d-7

T ;

tT) =

tT

Δ3

(<0) = dT

–

tT

min(dT

;

tT) =

dT

min(d-7

T ;

tT) =

d-7T

Δ1 =

dT

–

d-7T

ΔΔ

Δ

Figure 43 – Illustration of the calculation of temperature diff erences (Source: ERDF, WG of 09/07/13)

Variations compared to previous week

Fran

ce s

ynch

ron

ous

seri

es [

GW

]

Pow

er differen

ce [GW

]

0

10

20

30

40

50

60

50

60

70

80

90

100

110

November December January February March

- + + + - + - + - + + - - + - + -+ +

∆ power > 0∆ power < 0

France synchronous seriesWinter of 2011-2012 - Wednesday at 7pm-{02/11 ; 9/11; … 08/02 ; 15/02; …}

--

Figure 42 – Illustration of the calculation of power diff erences(Source: ERDF, WG of 09/07/13)

105

CAPACITY OBLIGATION / 4

The chosen method therefore has a very low degree of sen-

sitivity to the observed data used and accurately refl ects the

France temperature sensitivity for the year considered.

Lastly, some stakeholders questioned the use of a single year

of history to determine the gradient as opposed to a multi-year

history said to guarantee greater stability.

The chosen option of determining the France gradient on the

basis of one year is consistent with the more complex modelling

used by RTE. While RTE uses a fi ve-year history to align its forecas-

ting models, this history is used to determine the threshold tem-

peratures and the smoothing coeffi cients (optimisation under

constraints); gradients are determined for each year independently

(the model requires such freedom). This approach is very similar to

that adopted for the capacity mechanism: the threshold tempera-

ture and smoothed temperature are determined beforehand; the

gradients are calculated on the basis of actual data for the year.

The option of calculating the gradient on the basis of a single

delivery year does not constitute a factor of instability for the

mechanism. On the contrary, it is in line with existing processes

and enables consistency in the terms used in the handling of

temperature sensitivity in general (threshold temperature,

smoothing and gradient, which must be taken as a whole).

Furthermore, this choice reinforces the dynamic aspect of the

mechanism with a gradient that refl ects the temperature sensi-

tivity of the year in question and makes it possible to take into

account actions implemented by stakeholders without being

bogged down by the inertia of past gradients.

4.5.3.3.1.2.2 Variability of the results obtained for France

In response to the feedback received on the method of deter-

mining the gradients, studies were conducted on historical data,

focusing this time on the evolution of the gradient from one

year to the next.

The illustration opposite shows the evolution of the average

gradient on the half-hourly time slots chosen for PP1 from the

winter of 2006-07 to the winter of 2011-12.

Several points can be drawn from this analysis:

> First, the average growth in France temperature sensitivity

obtained with the method in the rules is in line with that found

in documents published by RTE (Adequacy Forecast Report

and Electrical Energy Statistics);

> Second, a “rebound” can be observed between the gradients

for 2009, 2010  and 2011. Additional analyses were carried

out to identify the causes of this change, particularly whe-

ther it was a reflection of a physical change in consumption

or the method itself. These analyses identified as the expla-

natory factor the distribution of EJP (peak day demand res-

ponse) days over the winter, which introduces an unknown

factor in the evolution of the gradient if load reduction

volumes are not taken into account in calculating the gra-

dient. If EJP was certified, consumption would be adjusted to

reflect the EJP activated. In any event, the deformation of the

scatter plot due to EJP only affects the incumbent operator;

the evolution of the gradient excluding EJP, which affects all

suppliers, is stable.

The evolution in the France gradient obtained with the method

in the rules accurately refl ects physical demand trends.

4.5.3.3.2  Provisions adopted on the temperature 

sensitivity of consumers

4.5.3.3.2.1 Guiding principles for choosing the method

of estimating temperature sensitivity

In parallel with the debate between precision and stability, many

stakeholders stressed the need to meet the following three

requirements:

(i) The calculation of the obligation must accurately refl ect the

contribution to the shortfall risk, no more and no less;

(ii) Non-temperature sensitive consumers must in no case be

penalised by possible uncertainties associated with the calcu-

lation of gradients;

(iii) Remotely metered consumers must not be penalised by

uncertainties associated with the profi ling system.

Fran

ce g

radi

ent (

MW

/°C

)

1,400

1,500

1,600

1,700

1,800

1,900

2,000

2,100

2,200

2007 2011201020092008

Figure 44 – Evolution of the average gradient on the PP time slots obtained with the method in the rules

106

These requirements aim to prevent full pooling, which would

completely dilute the objective of making market stakehol-

ders responsible for their temperature sensitivity. The rules

consequently incorporated a segmentation of the methods

adopted for each major category of consumption, taking

into account not only the process of determining consump-

tion (profiled or remotely metered) but also the physical para-

meters of this consumption (for example by distinguishing

between TSO losses, which are temperature sensitive, and

consumers connected to this network that are not tempera-

ture sensitive).

4.5.3.3.2.2 Method adopted for overall sizing of

temperature sensitivity per major category of

consumption

The studies based on past data presented above show that the

method of estimating the overall gradient by statistical regres-

sion on the basis of actually measured data enables the gra-

dients for France or per major category of consumption to be

estimated with satisfactory accuracy and stability.

RTE proposes to adopt this generic method to determine the

gradients corresponding to each major category of consump-

tion as a whole. The additivity of the method ensures that the

sum of the gradients of the various categories of consumption

corresponds exactly to the France gradient. Consequently, a

combination of this method with segmentation per major cate-

gory of consumption makes it possible (i) to target the real level

of temperature sensitivity in France and therefore to support

the mechanism’s security of supply objective, and (ii) to prevent

transfers of temperature sensitivity between major categories of

consumption, which would be contrary to the principles outli-

ned in the preceding section.

Also based on this proposal, it is considered in the rules that

the gradient is nil for certain categories of consumers owing

to a very low or statistically disputable temperature sensiti-

vity. This concerns all consumers connected to the public

transmission system and consumers connected to the public

distribution systems identified as non-temperature sensitive

by the distribution system operators.

Following strong requests from suppliers of profi-

led customers, smoothing was introduced in the

calculation of the overall gradient of profiled cus-

tomers: the rules adopt a linear extrapolation based

on the gradients obtained for the years DY-1, DY-2

and DY-3 via the generic method of estimating the

gradient. The total profiled customer gradient applied for year

DY therefore corresponds to the value of this linear extrapola-

tion. This provision presents the advantage of stabilising the

evolution of the profiled gradient from one year to the next146.

However, it causes a delay in taking into account changes in the

level and form of the temperature sensitivity trend among pro-

filed consumers, which could change radically with the deploy-

ment of smart meters and the switching of profiled consumers

to remote metering. This provision is not adopted for remotely

metered consumers.

4.5.3.3.2.3 Choice of method at the consumer level:

Redistributive issues

At an individual level, the gradient assigned to suppliers must in

theory reflect the real gradient of consumption in their custo-

mer portfolio in order to meet the objective of assigning obliga-

tions in proportion to suppliers’ contributions to the shortfall risk

and to enable them to benefit from any initiatives to manage

their temperature sensitivity.

With this in mind, it could seem preferable to adopt an indivi-

dualised approach across the perimeter of a supplier based on

the characteristics of its customers’ consumption. Indeed, a

normative approach would automatically lead to the pooling of

any temperature sensitivity management initiatives over all the

consumers in the class.

However, this approach presents some limitations:

> The flow reconciliation systems used on profiled sites are still

currently governed by a normative approach that cannot

be avoided with existing metering systems (ending profiling

would require the use of load curve data from sophisticated

meters);

> An individualised approach could raise fresh questions about

the assumed linearity of the power-temperature relationship.

The numerical result obtained with the raw method may not

have any statistical or physical reality, particularly for “small”

perimeters or for customers with “special” consumption

behaviours.

On the other hand, a normative approach intrinsically leads to

complexity, at several levels.

First, it involves defining a distribution key to assign to each

consumer a share of the temperature sensitivity of its class.

Defining this distribution key is a delicate matter (share of subs-

cribed power in relation to the sum of the subscribed power in

the class, the ratio for annual average power or during PP1, etc.).

146The basis on which the gradients chosen for the years DY and DY-1 are determined is 66% shared (the estimated gradients for years DY-1 and DY-2).

107

CAPACITY OBLIGATION / 4

In addition, when the distribution key is defined has an effect on

the precision and predictability of the gradients obtained:

> If the distribution key is determined before the delivery period,

the sum of gradients obtained will inevitably diverge from

the actual overall gradient. This approach must be ruled out

because it jeopardises the mechanism’s security of supply

objective;

> If the distribution key is determined at the end of the deli-

very period, the sum of the gradients can be normalised to

bring it into line with the real gradient. In this case, however,

a supplier’s gradient does not depend solely on consumption

within its perimeter but is also affected by the consumption

of other suppliers. A supplier that can accurately predict the

consumption of its customers will not be able to accurately

predict its obligation.

The method chosen to determine the sensitivity of consump-

tion to temperature on an individual level has effects only in

terms of redistribution of the gradient between stakeholders

(between individualisation and pooling) and not in terms

of sizing of the overall gradient. Thus, the choice between a

method based on individualised actual consumption and a

normative approach with a mutualising scaling factor147 comes

down to choosing how the overall gradient will be redistributed

between stakeholders (consumers and suppliers). This choice

considerably impacts the incentives for stakeholders to manage

their temperature sensitivity.

However, several market stakeholders (particularly suppliers of

profiled sites) expressed a desire to have more visibility on the

values of the gradients that will apply to their customers for a

given delivery year.

To meet the demands of various stakeholders, a compromise

must be found between the stability of the gradient (which

leads to pooling) and the principle of individualisation (which

provides incentives, exposing suppliers to the accuracy of

their forecasts).

When the mechanism is first introduced, RTE proposes to adopt

the following approaches:

> For profiled consumers, an approach based on the gradients

of the profiles used in the BRP/BM rules. This option was

requested by the suppliers of profiled sites, in order to have

better visibility;

> For remotely metered consumers, an individualised approach

per supplier perimeter. This option enables suppliers to esti-

mate the temperature sensitivity of their customer portfolio

solely on the basis of their forecast (no external

parameters) and thus to benefit from the actions

they take to manage the temperature sensitivity

of their customers.

4.5.3.3.3  Method adopted according to 

the type of consumption

4.5.3.3.3.1 Scope of application and volume

of associated gradients

It is possible to identify four categories of consumption that dif-

fer in how their load curves are constructed and their underlying

physical nature:

> PTS remotely metered consumption;

> PDS remotely metered consumption;

> Profiled consumption;

> Losses (PDS and PTS).

In the consultation organised by RTE, information was communi-

cated concerning the orders of magnitude of the various tempe-

rature sensitivities per type of consumption, giving an indication

of the stakes for these categories in terms of gradient volumes.

This information makes it possible to identify the main catego-

ries showing temperature sensitivity in order to adopt a rational

and proportionate approach. 85% of the temperature sensitivity

of consumption on the ERDF grid is accounted for by profiled

consumers, 11% by losses from the ERDF grid and only 4% by

remotely metered consumers.

It also makes it possible to identify the scope of the redistribu-

tive effects that can result from the choice of an individualised

approach based on actual consumption as opposed to a pooling

normative approach for PDS remotely metered consumption; it

is therefore a matter of deciding how to distribute this tempera-

ture sensitivity, which for the winter of 2011/12 is estimated at

74 MW/°C for customers connected to the ERDF grid.

Applying the principle of non-transfer of temperature sen-

sitivity (from temperature sensitive consumers to non-tem-

perature sensitive consumers and from profiled consumers

to remotely metered consumers), the redistribution of the

gradients is partitioned per category of consumption. This

involves applying the principle of consistency of the sum of

the individual gradients with the France gradient but for each

category taken separately: concretely, the sum of the gradients

of profiled consumers must correspond to the temperature

sensitivity of profiled consumers as a whole, no more and no

147The scaling factor is applied to a larger base, for example all profiled consumers or all remotely metered consumers. Efforts by these consumers to reduce their temperature sensitivity are therefore pooled.

108

less. This segmentation makes it possible to envisage diff erent

approaches for each category of consumption.

4.5.3.3.3.2 PTS remotely metered consumption

To complement the numerical data indicated above, various

illustrations are presented below concerning the link between

power and temperatures for customers connected to the PTS.

Figures 46 and 47 do not show any link between powers and

temperatures and illustrate the hypothesis of non-temperature

sensitivity of customers connected to the PTS.

In addition, application of a linear regression of the power at 7pm

over the temperature gives a slope equal to -0.18 MW/°C. This

gradient has no statistical or physical validity. Application of the

ER

DF

tota

l

Profiledconsumers

Load curve

= 1,567 MW/°C

= 74 MW/°C

= 201 MW/°CLosses

- 10.0 - 5.0 0.0 5.0 10.0

ERDFtemperature sensitivity

= 1,

842

MW

/°C

Other networks = 169 MW/°C

Figure 45 – Orders of magnitude of temperature sensitivity per category of consumption(Source: ERDF, WG of 09/07/13)

Dai

ly e

ner

gy (M

Wh

)

Average daily temperature (°C)

-5 0 5 10 15 20 25 300

50,000

100,000

150,000

200,000

250,000

Figure 46 – Daily energy consumed by direct PTS customers according to average daily temperature, in 2012

109

CAPACITY OBLIGATION / 4

°CMW

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

-6

-4

-2

0

2

4

6

8

10

12/01/2012

12/02/2012

12/03/2012

12/04/2012

12/05/2012

12/06/2012

12/07/2012

12/08/2012

12/09/2012

12/10/2012

12/11/2012

12/12/2012

12/13/2012

Figure 47 –Trend in temperature at hourly time step from 1 to 13 December 2012

Power consumed (MW)

Temperature (°C)

400

-10 -5 0 5 10

Tem

p. d

iffer

ence

(°C

)

Tem

p. d

iffer

ence

(°C

)

Po

wer

diff

eren

ce (M

W)

Po

wer

diff

eren

ce (M

W)

Mostly agricultural or industrialtype activities (manufacturing,

automobile industry, etc.)

Mostly tertiary type activities(hotels and restaurants,

public administrations, etc.)

Non-temperature sensitive load curvesTemperature sensitive load curves

-10 -5 5 10

Figure 48 – Illustration of the temperature sensitivity of remotely metered consumers(Source: ERDF, WG of 09/07)

110

method in such a case (i.e. redistribution of the -0.18 MW/°C) is

of no benefi t in terms of accurately allocating the temperature

sensitivity of consumers.

The provision adopted in the rules therefore corresponds to

the choice of a nil gradient for PTS customers. Their reference

power will be equal to the average power consumed during PP1

hours at the actual temperature, adjusting for certifi ed demand

response activated.

4.5.3.3.3.3 PDS remotely metered consumption

The system to which consumers are connected is not an entirely

appropriate boundary in terms of temperature sensitivity: some

consumers connected to a distribution system are temperature

sensitive while others are not and in fact have a similar profi le to

certain sites connected to the PTS.

The main diffi culty here relates to the determination

of an appropriate classifi cation to distinguish tem-

perature sensitive from non-temperature sensitive

consumers.

An initial classification based on the “APE” code (main activity

code) in the NAF listing was proposed during the consulta-

tion. This classification was not adopted for different types of

reasons:

> Legal reasons: based on common practices, it could be consi-

dered discriminatory148;

> Technical reasons: this classifi cation appears disputable

because temperature sensitive and non-temperature sensi-

tive consumption may be covered by the same activity code.

Taking this analysis into account, ERDF proposed a new classifi ca-

tion based on a technical criterion: average annual power. Concre-

tely, PDS remotely metered consumers with average annual

power of 175 kW or less are considered temperature sensitive.

Figure 49 represents the average gradient in %/C over three past

years for sets of consumers grouped together by average power.

For each year we can see a relationship between the average

power of the group and the relative gradient of the class. The

groups of sites with lower power levels are more temperature

sensitive (gradient signifi cantly greater than 0) while the largest

sites are not temperature sensitive (gradient not signifi cantly

diff erent from 0).

The next step is to determine, for the capacity mechanism, a

threshold group beyond which consumers are no longer consi-

dered to be temperature sensitive; this comes down to determi-

ning a criterion corresponding to an average power, in this case

the average power of this threshold group.

When the mechanism starts functioning, it is proposed that the

average threshold power be set at 175 kW; this parameter will be

revisable, like the other parameters of the capacity mechanism.

Incorporating this criterion, RTE proposes to adopt the following

approach:

> For non-temperature sensitive remotely metered customers

connected to the PDS, the treatment is the same as for PTS

remotely metered consumers: the gradient is set at 0;

> For temperature sensitive remotely metered customers

connected to the PDS, the generic method is applied, per sup-

plier perimeter, on the load curve corresponding to the sum

of the load curves of remotely metered customers connected

to the PDS that are considered to be temperature sensitive.

This provision provides an answer to the intrinsic limitations of

the generic method (physical non-representativeness of the

148Council of State decision of 22 October 2012 on the tariff order of 13 August 2009.

# of group of averageP(503 load curves per group)

Rel

ativ

e gr

adie

nt i

n %

/°C

-1

0

0 10 20 30 40 50 60

1

2

3

4

Threshold groupcorresponding to an

averageP of 175 kW

Consumersconsidered

non-temperaturesensitive

(gradient not significantlydifferent from zero)

Consumersconsidered highly

temperaturesensitive

Figure 49 – Illustration of customers’ temperature sensitivity based on average power (Source: ERDF, contribution submitted to

the Concerte site on 22/01/2014) 

RT7 RT8 RT9

111

CAPACITY OBLIGATION / 4

gradients obtained for small portfolios or atypical consumers)

by considering only temperature sensitive consumers.

Illustrations 50  and 51 represent the gradients obtained for

1,000 random samples with increasingly large populations (ran-

ging from 1 to 1,000 individuals) selected (1) among all remotely

metered customers and (2) only among customers considered

temperature sensitive.

We observe in case (1) that the average gradient obtained varies

greatly according to the selection sample. Thus, for a sample of

51 individuals, the gradient obtained is negative in more than 25%

of cases. Conversely, in case (2), for the same sample size, the gra-

dient is positive in more than 99% of cases and is even between

1.1 and 1.8% in 50% of cases. Setting the gradients of consumers

considered to be non-temperature sensitive to zero therefore

helps to stabilise the gradient obtained for small portfolios.

This provision adopted for customers considered to be non-tempe-

rature sensitive is in line with the system proposed in the consulta-

tion. It is a simplification measure, in view of the persisting difference

between the regulation framework applicable to top segments of

the customer portfolio (remote metering and contracts) and bot-

tom segments (profiling and regulated tariffs). By tending towards

standardisation of the gradient set at 0 for non-temperature sensi-

tive (industrial in practice) consumers, this provision ensures com-

pliance with the principle that a consumer that does not consume

on PP1 days has a zero obligation, in all cases.

Figure 50 – Random sampling among all remotely metered customers (Source: ERDF, contribution submitted to Concerte site on 22/01/2014)

Figure 51 – Random sampling among temperature sensitive customers (Source: ERDF, contribution submitted to Concerte site on 22/01/2014)

1

-4

-2

0

2

4

31 71

51

111 161 211 261 311 361 411 461 511 561 611 661 711 761 811 861 911 961

Number of aggregated load curves

Ave

rage

gra

dien

t per

load

cu

rve

in k

W/°

C

1

-4

-2

0

2

4

31 71

51

111 161 211 261 311 361 411 461 511 561 611 661 711 761 811 861 911 961

Number of aggregated load curves

Ave

rage

gra

dien

t per

load

cu

rve

in k

W/°

C

112

4.5.3.3.3.4 Profiled consumption

Two approaches were presented during the consultation to esti-

mate the temperature sensitivity of profiled consumers:

> The first approach corresponds to the application of the

method described in section 4.5.3.3.1 on the basis of defini-

tive profiled consumption. The method is therefore based on

(but does not duplicate) the existing profiling process, with

which stakeholders are familiar, and which enables a load

curve per consumer to be obtained. As it is perfectly addi-

tive, the calculation can be made on the profiled perimeter

of each obligated party, the hypothesis of linearity being

intrinsically validated for profiled consumption, by standar-

dised construction;

> The second approach corresponds to the creation of new

consumption profiles based on those described in the BRP/BM

rules with adjustment of the coefficients of the sub-profiles at

normal temperature which are extrapolated to extreme tempe-

rature. Temperature sensitivity is thus evaluated per sub-profile,

starting from the gradient calculated for all profiled customers,

based on series preceding the delivery year. This method requires

new alignment coefficients calculated for each half hour (Cprofi-

led). These alignment coefficients are determined at each time

step, using aligned profiled consumption as the reference, on the

delivery year, for all profiled sites extrapolated to the extreme tem-

perature determined by applying the method described in sec-

tion 4.5.3.3.1. This alignment covers both the energy alignment

necessary to ensure the consistency of profiled consumptions

with the total profiled consumption and an alignment correspon-

ding to an updating of the gradients previously determined, to

reflect changes in temperature sensitivity.

RTE and ERDF carried out joint and comparative analyses in

2013 of the results produced by these two methods. These ana-

lyses showed that the methods lead to similar results at the sup-

plier level and identical results for profiled customers.

Several stakeholders expressed their preference for the use

of gradients for sub-profiles defined in advance even if this

meant using new alignment coefficients, so that the sum of

the gradients would be in line with the gradient for profiled

consumers as a whole. The rules adopt a methodology of this

type, it being understood that the obligation calculated on all

profiled customers with this method is identical.

The rules therefore adopt a method that involves

estimating the gradient of a profiled consumer in

two stages:

Figure 52 (Source: EDF, WG of 07/06)

From 2009 to 2012, on the ten days of highest demand per winter (8am - 8pm time slot):> The alignment coefficient varies between 1.03 and 1.08

depending on the year> The coefficient is very volatile within the ten days of high-

est demand2009 2010 2011 2012

Average alignment coefficient 1.08 1.04 1.03 1.04

Daily volatility of coefficient

1.04 to 1.10

0.97 to 1.11

1.02 to 1.05

1.00 to 1.06

A 1% variation in the alignment coefficient at peak ≈ a devia-tion of 0.6 GW.

149The alignment coefficient as defined in Section 2, chapter C of the BRE-BM rules.

GradientsPS[h] = GProfil,S[h] x LCestim,S(M+14)[h] x PGADY[h]

> GradientsPS[h]: gradient of profiled site expressed in MW/°C;

> GProfil,S[h]: gradient corresponding to the sub-profile of the site

in the half-hourly step h of PP1 days expressed in %/°C. A list

of the applicable profiles is given in appendix F-M1 of the BRP/

BM rules in force at the beginning of the delivery year;

> LCestim,S(M+14): load curve of the site in the half-hourly step

h of PP1 days;

> PGADY[h]: profiled gradient alignment coefficient.

This alignment coefficient is determined after the delivery period

to ensure matching between the sum of the gradients of profi-

led sites and the total gradient for profiled consumers calculated

by applying the method described in section 4.5.3.3.1 on final

profiled consumption as a whole, adjusting for certified demand

response activated, and smoothed via a linear extrapolation over

the three years DY-1, DY-2 and DY-3 (see § 4.5.3.3.2.2).

4.5.3.3.3.5 Alignment coefficient and obligation

Concerns were raised during the consultation about the volati-

lity of the obligation level, especially for profiled consumption,

because of the alignment coefficient149.

The argument made directly projected the volatility of the align-

ment coefficient onto the volatility of the obligation. According to

this reasoning, if major discrepancies and volatility exist between

profiled and real consumption over peak periods, these discrepan-

cies and volatility should be reflected in the level of the obligation. It

was suggested that the figure could be as high as several GW.

113

CAPACITY OBLIGATION / 4

This link between the variability of the alignment coefficient and

the variability of the obligation does not seem to be borne out.

The alignment coefficient does not lead to any variability in France

consumption. On the contrary, for each half-hourly step, it ensures

consistency between the sum of the profiled consumption obtai-

ned from the modelling and actual profiled consumption.

RTE therefore conducted a study to test the hypothesis that a

correlation exists between the value of the alignment coefficient

and the value of reference power. For this purpose, the align-

ment coefficients for M+12 were retrieved for the delivery year.

In parallel with this, the reference power of profiled consump-

tion was calculated by applying the provisions adopted in the

rules and using the distributions of PP1 days corresponding to

the France consumption scenarios resulting from the Météo

France climate scenarios representative of the current climate.

Figure 53 shows that, for a same profiled reference power

value (56 GW), the average alignment coefficient on PP1 varies

between 1.00 and 1.03 (each column represents the alignment

coefficient associated with a distribution of PP1 hours).

The variability of the alignment coefficient is not therefore a

significant indicator of the variability of the capacity obligation.

4.5.3.3.3.6 Losses

The methods for determining the temperature sensitivity of

losses must be compatible with the provisions adopted for

the determination of the observed consumption

of losses. These provisions are being defined by

CRE and are unknown on the date of submission

of the rules.

However, as losses are proportional to withdrawal

and withdrawal is generally temperature sensitive,

the volume of losses is temperature sensitive. This

temperature sensitivity of losses also accounts for a significant

proportion of the France temperature sensitivity150  and cannot

therefore be overlooked. A method must thus be defined for esti-

mating this sensitivity. The generic method described in § 4.5.3.3

is suitable for estimating the temperature sensitivity of the losses

of each system operator.

In the same way as for the other categories of consumption,

questions arise concerning the redistribution of this tem-

perature sensitivity between the various stakeholders. This

is because covering the losses of each system operator can

involve several tens of suppliers and the system operator itself

for all or part of its losses.

This question is dealt with generically in the next section. Indeed,

the distribution of the gradient of losses between the various

suppliers and system operator is very similar to the situation of

a site where power comes from several suppliers and potentially

also from the consumer directly.

Figure 53 – Variability of the alignment coefficient for a same reference power

Alig

nm

ent c

oeffi

cien

t

Distribution of PP1 hours (56GW)

0,98

0,99

1,00

1,01

1,02

1,03

1,04

S1 S2 S3 S4 S5 S6 S7 S8 S9 S10 S11 S12 S13 S14 S15 S16 S17 S18 S19 S20 S21 S22

150The orders of magnitude presented in section 4.5.3.3 indicate a temperature sensitivity for ERDF losses of around 200 MW/°C, or about 10% of the overall temperature sensitivity for France.

114

4.5.3.3.3.7 Distribution of the temperature sensitivity

of consumption between various suppliers

Defining the rules that will determine how the capacity

mechanism functions requires putting generic market design

concepts into practice, including in extremely complex situa-

tions. This is the case with consumption sites that get power

from several suppliers. The framework outlined in this section

can also be transposed to the compensation of system losses

or to the obligation of consumers that buy directly on markets.

How the temperature sensitivity of consumption is distributed

between various suppliers needs to be considered in the light of

the type of commitment made by a supplier vis-à-vis a consu-

mer. In general terms, a distinction can be made between two

types of supply:

> A supplier can commit to supply a block of energy. In this

case, it is committed to supplying a defined volume of energy

regardless of external conditions, particularly the actual

temperature;

> A supplier can commit to cover the actual consumption of the

site. In the context of the capacity mechanism, this supplier

has therefore made a commitment to cover the consumption

of the site at extreme temperature. This commitment may

also entail coverage of the differences between injection and

withdrawal at the site.

On this basis, we can consider that the supply of a block of

energy does not take away a share of the temperature sensi-

tivity of the site, unlike a commitment by a supplier to cover

actual consumption. Concretely, the rules therefore consider

site NEBs to be non-temperature sensitive.

There then arises the question of the existence for any site of

a supplier committed to covering actual consumption (residual

of energy blocks supplied by other means) and the singleness

of this supplier. The concept of a supplier undertaking to cover

a site’s actual consumption is incorporated in the rules via the

affiliation of sites with the perimeter of one or more obligated

parties151. The absence of such a supplier does not constitute

an obstacle in the final analysis: it corresponds de facto to the

consumer choosing to cover its own consumption, including

at extreme temperature. In this case the rules provide for the

recognition of obligated consumers’ affiliation either

based on the declaration of the consumer or on the

absence of affiliation with the perimeter of a sup-

plier. In this case, the consumer is responsible for the

temperature sensitivity of its consumption.

The last step involves defining the singleness of such a supplier

at each time step. The existence of several such suppliers does

not appear compatible with the fulfilment of this responsibility.

At the least, it would require explicit coordination, failing which

the actions of one supplier would thwart those of others. Howe-

ver, the legal analyses conducted by RTE and the feedback

gathered from participants in the consultation did not allow this

singleness to be decided upon. By default, the rules include a

specific procedure for cases where there are several such sup-

pliers for a given time step: it involves going through the BRP

(Balance Responsible Party) to distribute the consumption and

temperature sensitivity of a site between several suppliers.

4.5.4 Taking into account certified demand response measures activated

In keeping with the choices made in France about market archi-

tecture since the Poignant-Sido workgroup of 2010, the capa-

city mechanism calls for demand response to be able to parti-

cipate directly in the capacity market as supply, i.e. to directly

secure capacity certificates through the certification process.

Putting this principle into practices requires specific procedures

to ensure that demand response capacity is not rewarded twice,

once through a reduction of the obligation and once through

the certificates issued. On this point, the decree stipulates that

“the observed consumption of a customer that has contributed

to the constitution of a demand response certification entity is

adjusted to reflect load reductions, in accordance with the capa-

city mechanism rules”.

As a result, for each PP1 peak hour, the observed consump-

tion of a consumer that has committed to a demand response

capacity that is certified and activated must be revised upward

by the amount of certified demand response capacity activa-

ted to calculate the obligation. This requires assigning an acti-

vated demand response amount to each consumer, based on

individual measurements (ideally) or by applying distribution

keys over a volume of attested load reduction attributed to the

demand response capacity certified as a whole. The capacity

mechanism rules proposed by RTE describe the methodology

for calculating a supplier’s obligation taking into account the

certified demand response activated. They do not, however,

address financial flows between stakeholders (supplier, consu-

mer and any demand-side operator involved).

4.5.4.1 Non-temperature sensitive consumers

The principle discussed above does not imply that a sup-

plier must know which certified demand response capacity is

151The rules therefore distinguish between the concepts of a “portfolio obligated party” and an “obligated party for declared supply”.

115

CAPACITY OBLIGATION / 4

activated within its perimeter. It needs only to know the sum of

the certified demand response capacity activated, or simply the

amount of observed consumption adjusted for certified demand

response activated, to determine its obligation. This is compa-

tible with the changes made to the regulatory framework for

demand response, i.e. the introduction into the technical rules

for rewarding demand response a segregation between inde-

pendent demand-side operators and the suppliers of sites that

activate demand response. This new regulation model, based on

the Competition Authority opinions of 26 July 2012 and 20 July

2013 and validated by the Energy Regulatory Commission in

its deliberations of 31 January 2013 and 28 November 2013,

is described in detail in RTE’s report on the NEBEF rules152. If

demand response is accurately evaluated, then the supplier will

be in the exact same situation (in terms of its obligation) as if its

customers had not reduced load. The supplier’s obligation the-

refore does not depend on the amount of certified demand

response capacity activated.

On the other hand, putting these regulatory principles into

practice becomes challenging when it comes to passing on the

cost of the obligation to the supplier’s customers. To invoice to

its customers the obligation amount resulting from the certi-

fied demand response activated, the supplier must either have

access to the sites concerned and corresponding demand res-

ponse volumes or have available from the system operator not

the measured consumption but the measured consumption

adjusted for load reductions. Otherwise, the supplier has no

other choice than to distribute the obligation resulting from

demand response among all its customers. This can create a

windfall effect for the consumer that reduces its consumption:

its obligation corresponds to its actual consumption (since the

amount of the obligation corresponding to demand response

is distributed between all consumers) but its load reduction is

also rewarded. For example, if its consumption is nil following

the demand reduction, it is not subject to any obligation and

it also receives remuneration corresponding to the amount of

the load reduction (through capacity certificates). However, the

same consumer reducing demand simply in order to reduce the

amount of its obligation will not benefit from this remuneration:

it will merely have a nil obligation. Thus, the decree’s principle of

non-discrimination between a reduction in the amount of the

capacity obligation due to load reduction and the certification

of demand response capacity is not upheld.

For the supplier to be able to pass through the cost of the obli-

gation accurately, it would have to have access to consump-

tion data per site adjusted for the demand response capacity

activated. This could create competition problems

that have been addressed in recent years, resulting

in the introduction of a regulated model between

demand-side operators and suppliers. These issues

do not relate specifically to the capacity market but

more generally to the relationship between inde-

pendent demand-side operators and suppliers; they

are also being addressed in the work being done on the imple-

mentation of the provisions stipulated by article L. 271-1 of the

Energy Code.

The alternative to having the financial impact of the explicit

valuation of demand response being addressed bilaterally and

through contracts would be to impose a regulated payment

on the sites in question, which could be incorporated into

the payment currently being defined in application of article

L. 271-1 of the Energy Code. In this case, the supplier would

not need to know the exact consumption per site adjusted for

load reductions. It would invoice customers on the basis of

consumption measured (without taking into account demand

response). The “surplus” obligation resulting from the activa-

tion of certified demand response is covered by the demand-

side operator. A change corresponding to an extension of

article L. 271-1 of the Energy Code to capacity would enable

energy and capacity to be treated in the same way and could

therefore be promoted.

In any event, by the time the capacity mechanism is in effect,

answers will have to have been found to the legal ques-

tions currently being examined to ensure that the supplier

is able to assign to consumers their share of the obligation

or to obtain the corresponding payment from the consumer

with in a regulated system.

4.5.4.2 Temperature sensitive consumers

For temperature sensitive consumers, the supplier’s gradient

is evaluated based on observed consumption adjusted for

certified demand response activated (it is on this scatter plot

that the linear regression is applied). As a result, the fact that

demand response capacity is activated within its perimeter will

have no impact on the analysis of the supplier’s temperature

sensitivity.

On the other hand, it is very difficult to comply with the prin-

ciple of non-discrimination between reductions in the obliga-

tion and certified demand response activated, since the linear

regression is applied to the entire delivery period, not just the

peak period.

152Block Exchange Notification of Demand Response. See report on the explicit valuation of demand response on the wholesale market on the RTE website.

116

Illustrationofpossibletreatmentsofdemandresponse

The following textbook case illustrates this phenomenon.

The hypotheses are as follows:

> We consider a temperature sensitive portfolio with a perfectly linear temperature dependency at temperatures below 15°C

with a gradient of 1 MW/°C;

> The PP1 hours correspond to hours at a temperature of 0°C;

> The extreme temperature is set at -5°C.

Case 1: Below 5°C, 5 MW of demand response

(non-temperature sensitive) is systematically

triggered.

The temperature/consumption chart used to estimate

the gradient is as follows.

The estimated gradient using the proposed method is

0.75 MW/°C (dotted orange line).

Observed consumption during PP1 is equal to 15  MW

(green dot). The application of the gradient yields a refe-

rence power of 18.75  MW (purple diamond) whereas the

consumer consumes 20 MW when the temperature is -5°C

(pink diamond).

Case 2: Below 5°C, temperature sensitive demand

response with a gradient of 0.5 MW/°C is systemati-

cally triggered.

The temperature/consumption chart used to estimate

the gradient is as follows.

The estimated gradient using the proposed method is

0.75 MW (dotted orange line).

Observed consumption during PP1 is equal to 17.5  MW

(green dot). The application of the gradient yields a refe-

rence power of 21.25  MW (purple diamond) whereas the

consumers consumes 20 MW when the temperature is -5°C

(pink diamond).

Pow

er (M

W)

Temperature (°C) Temperature (°C)

Pow

er (M

W)

-15 -10 -5 0 5 10 15 20 25-10

-5

0

5

10

15

20

25

30

-10 -5 0 5 10 15 20 25-10

-5

0

5

10

15

20

25

30

Power with no demand response Estimated gradient

Power with demand response activated

Reference power applied

Non temperature-sensitive demand response activated

Power with no demand response Estimated gradient

Power with demand response activated

Reference power applied

Non temperature-sensitive demand response activated

117

CAPACITY OBLIGATION / 4

It is easier to visualise this difference in treatment with a compari-

son of demand response capacity that is activated during all PP1

hours, but is not certified, and the same demand response capa-

city that is certified and activated in the same way. In one case, it

is possible to calculate a difference in obligation generated by the

“implicit” demand response, and in the other, it is possible (accor-

ding to precise methods to be described) to calculate the volume

of certified demand response factoring in the temperature sensiti-

vity of the demand response (by carrying out a linear regression on

the load reductions possible during PP2 peak hours). Two different

values are obtained: for highly temperature sensitive demand res-

ponse, certification is preferable; for demand response that is not

temperature sensitive (but applicable to temperature sensitive cus-

tomers), implicit demand response may be preferable (see illustra-

tion of how demand response can be treated below).

A regulated approach (extension of article 14 of the Brottes

Act to the capacity aspect) may raise a difficulty in identifying

the volume to which the regulated payment should be applied.

Addressing this difficulty would, strictly speaking, require

knowing how the supplier invoices the capacity. It can be assu-

med that the supplier invoices its customers applying the linear

regression formula on the consumptions actually measured (a

simplifying hypothesis which comes down to saying that the

supplier passes on to customers the exact portion of the capa-

city obligation generated by their consumption). In this case,

the supplier recovers a certain obligation volume from its cus-

tomers. The overall volume notified to it by RTE results from

the application of linear regression on the observed consump-

tions adjusted for load reductions. The resulting difference in

obligation could be assigned to the demand-side operator.

Ultimately, this comes down to assigning to demand response

a temperature sensitivity corresponding to the difference in gra-

dient between the two situations presented above. However, if

we carry out a linear regression on the demand response, the

demand response volume obtained does not match the diffe-

rence in obligation.

Before this approach was implemented, a decision would have

to be made about the method of determining the volume on

the basis of which the demand-side operator must compensate

the supplier.

4.5.5 Specific provisions for the compensation of losses on public transmission and distribution systems

The methodology for calculating the obligation corresponding

to compensation for losses on public transmission and distri-

bution systems must be consistent with the methods used to

determine the observed consumption associated with the com-

pensation for losses, which are to be proposed by CRE.

The approach proposed in the rules corresponds to a near-exact

transposition of the methods and systems used for other types

of consumption.

It involves a treatment of energy blocks supplied to compensate

losses on the PTS and PDS similar to that of declared supply (Site

NEB) on the one hand, and on the other an affiliation with a peri-

meter of the residual obligation created by differences between

the volume of losses observed during PP1 and the sum of the

energy blocks supplied. This obligation may be borne either by a

supplier or by the system operator.

4.6 Timetable for suppliers’ obligation

4.6.1 Before the delivery year

In the course of a capacity mechanism term, two events occur in

the period preceding the delivery year:

> Publication of the obligation parameters. They are published

no later than 1 January, four years before the delivery year;

> Publication of RTE’s forecast for the total capacity certificates

required for all suppliers to meet their capacity obligation, in

keeping with the provisions of paragraph I of article 18 of the

decree. The first forecast for a delivery year will be published

simultaneously with the capacity obligation parameters. They

will subsequently be published annually, no later than the first

of January of each year.

4.6.2 During the delivery year

As indicated above, the delivery year DY adopted in the rules

begins on 1 January of year DY and ends of 31 December of year

DY.

118

Within this delivery year, there is a delivery period

that corresponds to a formalisation of the “winter”

period, this being the period during which the shortfall risk

is concentrated and the PP1 days can be selected. The peak

period corresponds to the periods from 1 January to 31 March

and from 1 November to 31 December of year DY.

4.6.3 After the delivery year

4.6.3.1 Provisions included in the decree

Several provisions of the decree specify the organisation of the

different steps to be taken after the delivery year. They can be

applied directly.

Notification of the obligation: “At least fifteen days before the

deadline for transferring capacity certificates, the public electri-

city transmission system operator informs each supplier of the

amount of its capacity obligation.”

Transfer deadline: “The deadline for transferring capacity cer-

tificates, beyond which transfers of capacity certificates are no

longer possible.”

Collection deadline: “The deadline for the collection of capacity

certificates, or the date by which each supplier must hold the

amount of capacity certificates corresponding to its obligation;

it is set no later than two months after the transfer deadline.”

Notification of imbalances to obligated parties and of the

amount of settlements relating to capacity rebalancing by

obligated parties: “No later than fifteen days after the transfer

deadline, it [RTE] informs each supplier of its imbalance and the

settlement corresponding to its capacity rebalancing.”

4.6.3.2 Methods adopted in the rules

The first milestone after the end of the delivery year is the noti-

fication of the obligation. The provision adopted in the rules

corresponds to a notification of the obligation no later than

1  December of year DY+2. This milestone is set based on the

time required for the recovery of the observed consumption

data, particularly for profiled consumption.

Starting from the date by which RTE is to have informed obligated

parties of the amount of their obligation, the transfer deadline

for a given delivery year is set at 15 December of year DY+2,

in compliance with the provisions of the decree. Consequently,

the provision of the decree imposes a collection deadline of

15 February DY+3 at the latest.

It is then proposed that the deadline for notification of the sett-

lement relating to capacity rebalancing by obligated parties be

set at 20 December of year DY+2.

Collecting and distributing the settlement is a two-stage pro-

cess, beginning with the collection of the settlement owed by

obligated parties followed by the payment of amounts owed

to obligated parties within the limit of the amounts collected.

Consequently, a deadline has been added for the collection

of the settlement owed by obligated parties, and it is set at

15 January of year DY+3, after which RTE pays any amounts due

to obligated parties.

4.6.3.3 Incorporation of the public offering

The Energy Code includes an obligation for suppliers to orga-

nise public offerings to sell any certificates held in excess of their

obligation153.

In response to requests made by several stakeholders, the rules

adopt a set of provisions to facilitate the implementation of this

obligation for suppliers:

> The concept of suppliers’ surplus certificates is directly

incorporated in the rules, and corresponds to the diffe-

rence between an amount of certificates and an obligation

amount;

> Suppliers will be notified of surpluses when they are informed

of their level of obligation. The volume of certificates held on

the date of notification of the level of their obligation will be

considered for this purpose. The surplus amount will be upda-

ted following each change in the number of certificates held;

suppliers can find information regarding their surplus directly

in the register;

> Suppliers will thus be able to organise public offerings to meet

their obligation between the time they are notified of their

obligation and the transfer deadline;

> The procedures adopted for the capacity certificates register

will allow interfacing with any organised trading platforms. It

will thus be simpler to organise public offerings working from

the register and through trading platforms.

153Article L-321-16.

119

CAPACITY OBLIGATION / 4

120

The certification process involves allocating to each capacity

the amount of certificates that corresponds to its contribution

to reducing the shortfall risk.

A capacity’s contribution to reducing the shortfall risk depends

on its specific characteristics, the power system in which it ope-

rates and the security of supply criterion set by public authori-

ties. Certification parameters must therefore be chosen in such

a way as to reflect a capacity’s contribution to reducing the

shortfall risk as accurately as possible. The general provisions are

the framework within which the certification process unfolds.

5.1.1 Players involved in capacity certification

Operators of generation and demand response capacity are affec-

ted by the certification aspect of the capacity mechanism. They can

either act as their own capacity portfolio manager, a role created by

the decree, or designate a capacity portfolio manager that will bear

the financial responsibility for imbalances within their portfolios.

5.1.1.1 Operator

Under article 321-16 of the Energy Code, opera-

tors must file a certification request with the public

transmission system operator for any generation or

demand response capacity connected to the public

transmission system or public distribution system154.

Participation is thus mandatory for all capacity.

The rules provide detailed definitions of capacity operators and

categorise them according to the nature of their capacities

(generation or demand response).

5.1.1.1.1 Operator of generation capacity

A generation capacity operator can be:

> Either the holder of the Transmission Network Access

Contract (CART), the Distribution System Access Contract

(CARD) or the calculation service contract for an injection

site;

> Or a legal entity with a mandate from the holder of the Trans-

mission Network Access Contract (CART), the Distribution

System Access Contract (CARD) or the calculation service

contract for an injection site.

5.1.1.1.2 Operator of demand response capacity

The operator of demand response capacity, whether operated

directly by a consumer or indirectly through an aggregator, can be:

> Either the holder of a Network Access Contract, a calculation

service contract, a single contract or a regulated tariff contract

for extraction sites;

> Or a legal entity with a mandate from the holder of the

Network Access Contract, calculation service contract, the

single contract or regulated tariff contract for the extraction

site or for each extraction site constituting the demand res-

ponse capacity.

5. CAPACITY CERTIFICATION

Supply in the capacity market is constituted by capacity certi-

ficates issued by RTE and allocated to operators of generation

and demand response capacity that contribute to security of

supply. This chapter discusses capacity certification, i.e. the pro-

cess by which each operator is allocated an amount of certifi-

cates proportionate to the benefits provided to the power sys-

tem in terms of reducing the shortfall risk.

The chapter begins with a review of the general provisions

governing certification, particularly the identification of stakhol-

ders affected, how their capacity level is determined, and the

time periods and methods applied in calculating this capacity

level (§ 5.1). Details are then provided about the options selec-

ted in RTE’s proposal: definition of the PP2 period during which

the capacity level is determined (§ 5.2), the methods used to cal-

culate availability factoring in the technical constraints of capa-

cities (§  5.3), practical implementation of certification, particu-

larly timetables (§ 5.4), and the principles of rebalancing (§ 5.5).

In the interest of transparency for all involved, the certification

process is based on extensive data collection (§ 5.6). To comply

with regulations, the certification process also includes consis-

tency checks, some aspects of which are described at the end

of the chapter.

154The decree also stipulates (II, article 8) that certification request documentation is to be presented to the operator of the system to which the unit is connected.

5.1  General provisions governing the certification of capacities 

121

CAPACITY CERTIFICATION / 5

5.1.1.2 Capacity portfolio manager

Similarly to the balance responsible entity system in place in

the energy market, the decree introduced the role of the capa-

city portfolio manager to spread capacity availability risks when

determining the effective capacity level.

The capacity portfolio manager is the legal entity financially

responsible for the imbalances of the capacity operators in its

portfolio. It pays the penalty charged to operators as laid out in

article L. 335-3 of the Energy Code. Operators can act as their

own capacity portfolio manager or enter into contracts with

capacity portfolio managers. Capacity portfolio manager status

is acquired by signing a contract with RTE.

5.1.2 Capacity level

5.1.2.1 Certified capacity level and effective capacity level

5.1.2.1.1  Overview of the provisions of the decree

The decree establishes a certification process based on a certified

capacity level followed by verification of the effective capacity level.

The certified capacity level […] reflects the contribution of the

capacity to reducing the shortfall risk during the delivery year.

The effective capacity level reflects, for a given delivery year,

the real contribution of the capacity to reducing the shortfall risk

for a given delivery year155.

These two concepts are inseparable.

5.1.2.1.2  Two approaches: actual capacity or 

normative basis

The real level of security of supply depends on the effective avai-

lability of capacity when supply is tight. As capacity is certified in

advance (from three to four years before the deli-

very period for existing generation capacity) and

the effective capacity level is measured after the

delivery period, imbalances may be observed. Two

approaches can be taken to measuring imbalances:

> The approach based on actual capacity involves an indivi-

dualisation of the imbalance between the certified capacity

level (on the basis of which capacity certificates were issued)

and the effective capacity level: the initial certification may be

based on self-assessed data (operators have the most infor-

mation about expected availability);

> The normative approach involves pooling imbalances

between certified capacity levels and effective capacity levels:

in this case initial certifications may be based on normative

values (typically per technology) associated with real-time

minimum commitments.

However, the decree specifies that operators are to indicate

in their certification requests “the forecast availability of their

capacity during the PP2 period”. Hence the regulations explicitly

provide for a mechanism that will hold capacity portfolio mana-

gers responsible for imbalances between their commitment to

a level of certified capacity and their effective capacity level. This

provision is compatible with the philosophy of the approach

based on actual capacity. A generic approach based on the indi-

vidualisation of imbalances has therefore been adopted.

This approach presents several advantages.

Firstly, with an approach based on self-assessed rather than nor-

mative data, the certified capacity level of an operator is not

limited by the performances of other operators. A normative

approach would penalise the most efficient operators in a given

sector and benefit the least efficient ones. With an individua-

lised approach, each operator can reap the full benefits of any

155Decree 2012-1405, Article 1.

Figure 53 – Relationship between certified capacity level and effective capacity level(Source: RTE, Market Access Committee meeting of 11/07/2013)

Effective capacity levelCalculated based on effectively available power

Starting 3-4 years before delivery year

Certified capacity levelCalculated based on forecasts

Année de livraison Delivery year

122

improvement in its own performances. It creates a powerful sys-

tem of accountability. Operators decide on the projected avai-

lability of their capacity. To avoid distortion and strategic beha-

viour, they must be held accountable for differences between

actual and forecast availability.

Secondly, the approach should lead to virtuous behaviour,

notably by creating a closer link between the physical state

of the system and the information conveyed by the capacity

mechanism. And maintaining this link through to the last reba-

lancing gate should pave the way for a dynamic management

of capacity adequacy. For instance, is operators anticipate that

they will make a lesser contribution to reducing the shortfall

risk (technical problem, exceptional maintenance or decision

to close a unit), they have an incentive to rebalance, and the

resulting decline in the level of capacity certified can trigger the

creation of new capacity and peak demand management mea-

sures. This feedback loop appears to be an important factor

in the stability of the mechanism, creating a restoring force

that binds the two sides of the supply-demand balance. It

is particularly important for capacity that can be

deployed rapidly, especially demand response

and other peak demand management actions.

Not taking into account short-term resources would

mutualise capacity risks with the cost being borne

by the whole community (in practice, it would mean

increasing the security factor for all consumers).

A third advantage of this approach is its simplicity:

the number of capacity certificates allocated to a

resource depends directly on the attested availa-

bility and technical characteristics of the resource

during the PP2 peak period. This “self-assessment

+ verification” system circumvents the problem of

defining normative coefficients that are often chal-

lenged by the operators that claim to do be more

efficient. Indeed, a normative approach requires

determining capacity certificate allocation values

ahead of time and generates significant distortion,

particularly in terms of the bases for calculating refe-

rences for allocation values.

Lastly, this approach reduces the risk of “phantom

capacity” appearing because real availability is taken

into account. It ensures that capacity that is not avai-

lable during the peak period will not be rewarded

through the capacity mechanism. Of course this

system would not be appropriate if the objective

was merely to remunerate existing assets by offsetting some

stranded costs, but, as indicated in chapter 1 of this report, such

is not the purpose of the mechanism introduced in France.

5.1.2.1.3  Intermittent capacities

The applicability of the generic approach described above (cer-

tification based on self-assessments, restatement post verifica-

tion) to intermittent or non-controllable capacities was discussed

extensively during the consultation. Some participants noted

that the intermittent nature of some capacities would necessarily

require the application of a normative approach, since the availa-

bility of these capacities depends exclusively on external parame-

ters156. They also stressed the impact this volatility would have on

all stakeholders and on the quality of the signal conveyed by the

mechanism. Since a large share of intermittent capacity benefits

from purchase obligations, the law already provides for a specific

system to be created for these capacities (to be proposed by CRE).

Based on these considerations, the possibility was included in

the rules for an operator of intermittent capacities to opt for an

alternative certification system. Under this alternative system,

certificates are allocated to operators based on normative coef-

ficients, rather than on their self-assessments with subsequent

adjustments following the verification of effective capacity

levels. This gives operators options with regard to the treatment

of the risk associated with the primary source.

Two concerns should nonetheless be mentioned in considering

this system:

> Technical studies conducted by RTE (presented in this chapter)

did not support the assertion that the application of the generic

system to intermittent capacities would jeopardise the quality

of the capacity mechanism signal: as of today, the main risks

for the level of certified capacity, and thus for signals relating to

capacity, are those that could affect nuclear capacity;

> This approach could prevent the full use of all resources through

the capacity mechanism, notably demand response resources.

5.1.2.1.3.1 Structure and volume of intermittent risks

To assess the impact of the certification of intermittent capa-

cities using an approach based on accurate availability data,

The generic approach adopted involves certifying capacity based on availability forecasts submitted by operators and calculating a settlement after the fact to reflect the level of effective capacity meas-ured based on availability during the PP2 period.

156A parallel can be drawn with climatic correction used on the obligation side to ensure that obligated parties’ obligations are not affected by weather contingencies. If weather contingencies are neutralised in calculating the obligation, they should also be neutralised in the certification process. However, the restatement carried out to calculate the obligation does not include all external risks, but specifically weather contingencies. The aim is to compare the actual situation to a situation representative of the risk against which the system is seeking to protect itself, i.e. a cold spell. This is why it is proposed in the draft rules that a correction be made for temperature sensitive capacities (not intermittent sources, but some demand response for example) so that the capacity level allocated to them is consistent with their contribution in a “one-in-ten-year cold conditions” type situation.

123

CAPACITYCERTIFICATION / 5

Figure 54 –Standard deviation of eff ective capacity level for wind and run-of-river power

Wind (standard deviation in MW and %) Run-of-river (standard deviation in MW and %)

Stan

dard

dev

iati

on (%

)

Stan

dard

dev

iati

on (M

W)

Stan

dard

dev

iati

on (%

)

Stan

dard

dev

iati

on (M

W)

0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

0

50

100

150

200

250

300

350

400

450

0

50

100

150

200

250

300

350

400

450

2008 2009 2010 2011 2008 2009 2010 2011

    Without milestones (MW)

    Milestones 5 days (MW)

Without milestones (%)

Milestones 5 days (%)

RTE conducted technical studies on the structure and volume

of the risks to which intermittent capacities are subject. The

goal was to estimate the impact the certifi cation method used

for intermittent capacities has on the “stability” of the capacity

mechanism.

These studies are based on actual production between 2008

and 2011 and the results quantify the variability of wind and

run-of-river power generation risks. The charts below show the

results in terms of the variability of capacity levels with days

selected over the entire delivery period or with milestones limi-

ting the number of days in March and November to fi ve.

Two conclusions can be drawn from these studies:

> Variability is limited within a given year (approximately 300 MW

for wind power and 200 MW for run-of-river power);

> The risk may however be more signifi cant for one technology:

the standard deviation can represent up to 17% of the eff ective

capacity level for wind power and 7% for run-of-river power.

These results show that the variability of wind and run-of-river

power in past years was low in relation to the power sector,

especially compared with nuclear capacity (standard deviation

of about 1,000  MW). The volatility of capacity supply mainly

corresponds to risks relating to nuclear power generation.

Looking ahead, forecasts were drawn up for 2016-17 to estimate

the variability of wind and photovoltaic power generation. The

variability of intermittent renewable energy sources remains

limited in 2016-17 with a standard deviation of approximately

150 MW for PV and 500 MW for onshore wind. Variability is thus

still lower than for nuclear power.

Figure 55 – Comparison of the breakdown of annual wind and run-of-river power production

An

nu

al g

ener

atio

n (T

Wh

)

Wind (distribution of annual generation in TWh) Run-of-river (distribution of annual generation in TWh)

32

34

36

38

40

42

44

46

16

18

20

22

24

26

28

30

124

Another study was conducted based on probabilistic simula-

tions to complement the analysis of the structure of intermittent

risks, focusing notably on the breakdown between intra-annual

risks, which are sensitive to the location in time of PP2 days, and

inter-annual risks, which are sensitive to risk realisation during

the delivery year. Within this context, the variability of annual

production in these segments was studied for a large number of

scenarios assuming no changes in the fleet.

Two observations can be made:

> Inter-annual variability in wind power generation is low: the

main risk is intra-annual;

> Inter-annual variability of hydropower generation is high: this

is due to differences in water conditions between years. The

intra-year risk, however, is lower. Based on projections for

2016-17, the total variability of run-of-river hydropower is

estimated at around 600 MW.

Differences between the characterisation of the intermittence

of run-of-river hydro and wind power generation have distinct

consequences for the signal conveyed to the market and the

system:

> A wind capacity operator has no new information about the fore-

cast production of its capacity when the delivery period begins;

> A run-of-river capacity operator has more reliable information

about its forecast production when the delivery period begins.

Choosing whether to treat the risk associated with water

conditions for run-of-river hydro generation, which can be

predicted before the start of the delivery period, through an

approach based on actual results or a normative approach,

means choosing whether the real state of security of supply

in the delivery year in question is targeted or not.

5.1.2.1.3.2 Impact of a normative approach

Making a separate treatment of intermittent capacities possible

is not without consequences for the mechanism.

The first question it raises is whether normative cer-

tification should be an option for all capacities. With

no adjustments made to reflect observed availability,

a purely normative approach results in certificates

being allocated to capacities irrespective of their

actual contribution to reducing the shortfall risk.

A normative approach leading to a total absence of

imbalances, regardless of the actual availability of the

capacity, could induce undesirable windfall effects157.

This approach heavily penalises demand response.

Secondly, the normative approach does not allow all

resources available to the capacity mechanism to be utilised,

particularly the addition of new capacity as the delivery year

approaches. Risks relating to water conditions can typically be

detected between year Y-3 and the delivery period. In this case,

the procedures stipulated in the decree and implemented in the

rules (rebalancing by the operators in question) must allow this

information to be communicated to the market (for example a

rise in prices following a reduction of the expected actual avai-

lability of certain resources) to create economic space for new

capacity (typically demand response on dates close to the deli-

very year). These resources cannot be utilised with a normative

approach.

Thirdly, the option of applying a normative approach to inter-

mittent capacities raises the issue of the equal treatment

of all capacity. This is an especially important consideration

because stakeholders have underlined the fact that all types of

capacity, controllable or not, is subject to external risks.

The rules make it possible for the operator of non-controllable capacity (wind, photovoltaic, run-of-river hydro power) to choose between one of the two following systems when certifying capacity:

> The generic system (certification based on self-assessed data with subsequent restatement based on verified availability) applicable to con-trollable capacity;

> An alternative system (certification based on normative coefficients calculated for each technology, neutralising the risk associated with the primary source).

This option addresses the expectations expressed during the consultation and incentivises opera-tors to forge strategies to hedge variability risks (particularly by adding flexible capacity such as demand response). It thus allows a distinction to be made between external risks associated with the primary source and those that are within the operator’s “control”.

The coefficients used with the normative system are based on adequacy studies and reflect the average contributions of these technologies to reducing the shortfall risk.

This ability to choose between the two approaches is modelled after the renewable energy support schemes adopted in some European countries, which give operators an option between partici-pating in the market or a de-risked system (Ger-many and Spain are examples).

157If capacity level is determined over a relatively long period (around ten years), without no specific treatment, a capacity that is closed could be assigned a capacity level for ten years, though it would admittedly diminish each year over the period.

125

CAPACITY CERTIFICATION / 5

5.1.2.1.4  Unforeseeable risks

Some generators indicated during the consultation that they did

not want the evaluation of their effective capacity level measu-

red after the availability verification to take into account unfore-

seeable risks that affect availability in real time. These include all

events that are beyond the control of the operator and result in

temporary unavailability (equipment failures, etc.).

Accounting for unforeseeable risks presents the same type of

difficulties as those outlined above. It is indeed not easy to esta-

blish a rule ahead of time for distinguishing between risks that

are unforeseeable (and thus acceptable) and foreseeable (consi-

dered “abnormal”). An incentive system similar to that used for

imbalance settlements in energy markets, assigning to each

stakeholder the cost of the rebalancing the system requires,

should provide an adequate response to these issues and avoid

introducing a rule for identifying the nature of risks that would

inevitably be complex.

Because they can rebalance before the delivery period (see

chapter 6), operators are able to adjust their certified capa-

city levels to take the realisation of unforeseeable risks into

account: they can revise their capacity levels downward during

periods or years when numerous unforeseeable risks occur, or

upward if few unforeseeable risks materialise. The rules also

include various provisions to attenuate the effect of such

occurrences:

> The difference between certified and effective capacity levels

is evaluated at the capacity portfolio manager level, making it

possible to spread risks;

> Availability commitments are made for the whole PP2 period,

so risks can be spread over time.

Some stakeholders said that while such measures may be

necessary, they are not sufficient to ensure fair competition

in the capacity market, particularly with respect to stakehol-

ders with large perimeters. A specific provision was therefore

included in the rules to limit the application of rebalancing costs

if unforeseeable risks affect generation or demand response

capacity.

The system adopted in this provision (two zero-cost rebalancing

“tickets”) is designed to maintain the incentive for stakeholders

to submit their best availability forecasts ahead of time (tickets

valid only for two days after the unforeseeable event is repor-

ted and for a volume proportional to the impact of the event

on certified capacity). Operators will therefore have to report all

unforeseeable risks affecting their resources, including capacity

of less than 100 MW158, to be issued rebalancing tic-

kets. This new system will make operations in the

power system even more transparent.

5.1.2.2 Certification based on self-assessed

data with verification of availability

Under the generic approach, the principles outlined above

involve basing the number of capacity certificates allocated to a

resource to the self-assessed data provided by the operator. All

capacity is certified based on its specific characteristics. Certified

capacity levels are based in part on the estimated availability of

the capacity during the PP2 period, per the terms of the decree:

“The certified capacity level […] takes into account in particular

the estimated availability of the capacity during the PP2 peak

period of the delivery year” (article 1).

All self-assessed data submitted is then compared with the

effective capacity level measured during PP2 in the delivery

year. The effective capacity level is calculated using the same

method as the certified capacity level. The difference between

the two is the basis for the imbalance settlement subsequently

calculated.

Consistency between certified and effective capacity levels is

thus guaranteed. Because the same method is applied in cal-

culating certified capacity levels and effective capacity levels,

certification parameters are set at the start of the mechanism

term and maintained throughout. Only data that can cause the

capacity level to change are reported by operators. They have

the information necessary to anticipate the amount of certifi-

cates they will receive to match their effective capacity level.

The certified capacity level is thus based on the operator’s fore-

cast of its effective capacity level. The proposed method thus

mirrors the system in place in the energy market: operators

submit data based on their own calculations and imbalances are

determined based on actual results.

The deadline for initial certification is at least three years before

the delivery year for existing generation capacity (the decree of

158In this regard, the provision goes beyond the principles of EU Regulation 543/2013.

Rebalancing plays a central role in the mecha-nism: operators can rebalance at any time, including during the delivery year, to adjust their certified capacity level as they obtain more spe-cific information about the availability of their resources during the mechanism term.

126

December 2012 specifi es that a deadline must be set for opera-

tors to submit certifi cation requests). They are not expected to

submit fi rm and fi nal assessments of the projected availability

of their capacity, since rebalancing is possible. Rebalancing cor-

responds in a way to a “re-certifi cation” of capacity, refl ecting

adjustments to operators’ forecasts based on new information

about their capacity. The cost of the rebalancing, which is added

to the cost of the certifi cates required for rebalancing by the

capacity portfolio manager, refl ects the cost to the community

of disclosing the new information. The cost is zero before the

delivery year starts and rises progressively thereafter, with the

cost of imbalances, during the delivery year.

5.1.3 PP2 peak period

The decree specifi es that the “peak period” refers to “the hours

of a delivery year during which the shortfall risk is greatest, par-

ticularly those during which national demand is highest”. The

peak period used in the capacity certifi cation and verifi cation

methods is called the PP2 period.

At the time of certifi cation, the certifi ed capacity level must refl ect

the capacity’s contribution to reducing the shortfall risk, meaning

it must take into account projected availability during the PP2

peak period. The real-time measurement of eff ective capacity

availability must therefore focus on this same PP2 period.

In a year with shortfall situations, the best way to assess each

capacity’s contribution to reducing the shortfall risk is to

measure its availability during the actual shortfall hours. PP2

must therefore include these hours. However, the capacity

mechanism is intended to provide insurance by rewarding capa-

city that contributes to security of supply even in years with no

shortfall situations. As a result, the PP2 period must be defi ned in

such a way as to provide the best estimate of a capacity’s contri-

bution to reducing the shortfall risk when no shortfall occurs.

5.1.4 Calculation of the capacity level

Diff erent methods of calculating the capacity level were pro-

posed during the consultation, notably focusing on the algo-

rithm used. These proposals were combined into a formula cen-

tred around:

> Available power during PP2

> A coeffi cient enabling technical constraints to be taken into

account (defi nition and calculation presented in § 5.1.4.2).

5.1.4.1 Available power

The principle applied in calculating available power must be that

a capacity that is not available during the peak period does not

contribute to reducing the shortfall risk and will therefore not be

allocated any capacity certifi cates.

In the rules, available power is defi ned as the power that can be

made available during PP2. Generation capacity that does not

produce energy but could do so, or demand response capacity

that is not activated but could be, is considered to be available

during the period in question.

Figure 56 – Organisation of the certifi cation process

Initialcertified

capacity level

(Initialavailability)

Difference

Rebalancing

PP2

Rebalancing is flexible and possible even during delivery year

Effectivecapacity level

(Actualavailability)

Certifiedcapacity

level afterrebalancing

(Availabilityafter

rebalancing)

127

CAPACITYCERTIFICATION / 5

5.1.4.2 Technical constraints

Capacity can be subject to technical constraints (other than

availability) that aff ects its contribution to reducing the shortfall

risk. Examples include:

> Energy constraints;

> Constraints linked to controllability/intermittence;

> Dynamic constraints.

How these constraints are factored in when calculating certi-

fication levels depends on the weighting assigned to them in

determining the capacity’s contribution to reducing the short-

fall risk. They must therefore be measured and verified.

5.1.4.2.1  Energy constraints

The key risk the capacity mechanism must address is a cold spell

with a particular time structure that could range from several

hours to several days in a row.

On a theoretical level, the certifi cation process must take into

account technical constraints such as daily energy constraints

(number of hours per day during which the capacity can be being

activated at maximum power), weekly energy constraints (num-

ber of consecutive days of a week during which the capacity can

run) and seasonal energy constraints (number of days per year

during which the capacity can operate).

Seasonal constraints are less of a concern if the capacity can be

activated for two weeks in a row. On the other hand, capacity that

can only be activated one day a week makes a real contribution

to reducing the shortfall risk but it is limited, regardless of its sea-

sonal availability. In the interest of simplicity, the seasonal energy

constraint is not taken into account in the rules for the fi rst

year of the mechanism but can be integrated into a later version.

Following the publication in September 2013 of the report

accompanying the draft rules, which included a chart illustrating

how daily constraints were taken into account, some stakehol-

ders questioned whether it was necessary to only have capacity

that could be activated ten hours per day to contribute to security

of supply and the mechanism’s effi ciency.

This “activatable capacity” factor neutralises diff erences

between generation and demand response capacity by basing

the issuance of certifi cates on contributions to security of sup-

ply. The entire shortfall landscape is taken into account in

estimating each capacity’s contribution. This provision is in

keeping with the decree, which requires that only one “capacity

certifi cate product” be adopted. It will thus facilitate trading, at

least when the mechanism is fi rst implemented. All other pro-

visions considered would inevitably have led to the creation of

diff erent products, adding another layer of complexity.

5.1.4.2.2  Controllability / intermittence

5.1.4.2.2.1 Methods based on certifi cation procedure

adopted

A capacity’s controllability or intermittence is fi rst taken into

account through the approach adopted for certifi cation.

If certifi cation is based on actual results, then the operator will spe-

cify the variability of its capacity in its certifi ed capacity level decla-

ration and ultimately receive the amount of certifi cates correspon-

ding to its real contribution (producible energy during PP2).

With a normative approach to certifi cation, this principle does not

apply. According to regulations, the normative approach must refl ect

the average contribution of capacities to reducing the shortfall risk.

5.1.4.2.2.2 Normative certifi cation and contribution to

reducing the shortfall risk (capacity credit)

Adding intermittent generation capacity to a power system

does not reduce the shortfall risk in proportion to past average

producible power values. To estimate this contribution to secu-

rity of supply, a contribution coeffi cient (CC) must be applied to

translate these technologies’ average contribution to reducing

the shortfall risk.

Figure 57 – Illustration of capacity credit based on installed wind power in Great Britain (Source: IEEE Power Energy Society)

Peak

Installed wind capacity

Cap

acit

y cr

edit

0 10 20 300%

5%

10%

15%

20%

25%

30%

ELCC / LOLE

ELCC / LOLP (90%)

ELCC / LOLP (95%)

ELCC / LOLP (97%)

128

The value of this coefficient depends (i) on the capacity consi-

dered, (ii) on the amount of intermittent capacity already in the

system, and (iii) more generally, on the broader power system

(structure of demand, structure of the fleet excluding intermittent

capacity, interconnection capacity). The goal is to determine the

correlation between the intermittent risk and shortfall situations.

The method adopted to determine the contribution coefficients

for eligible technologies (wind, solar, must-run hydro) is similar

to that used to estimate contributions to the shortfall risk of

different consumption profiles: it is based on equivalence with

a perfect resource, with no constraints, that receives 1  MW of

certificates per MW installed.

The value of the contribution coefficient can then be estimated

based on the value of the certificates issued to the technologies

and past records of their producible energy at peak.

Values adopted in the rules for the contribution coefficient per

technology

For the first delivery years of the capacity mechanism, the rules

adopt the following CC values for the technologies in question:

> CChydro = 85%

> CCwind = 70%

> CCsolar = 25%

5.1.4.2.2.3 Length of historical data required

Certification calculations based on the normative approach

incorporate past producible energy values for the capacity. The

length of historical data used varies depending on the techno-

logy. These lengths are determined in such a way as to be:

> Sufficiently long for the average producible energy value to

be close to producible energy value certified. This allows risks

associated with the primary source to be smoothed.

> Sufficiently short for structural changes in the capacity to be

taken into account within a relatively short period of time and

consistently with the timeframes of the mechanism.

5.1.4.2.3  Dynamic constraints

The dynamic constraints of generation facilities are not explicitly

factored into the rules. They are taken into account indirectly

through the definition of PP2 and the certification process with

verification of availability. Dynamic constraints that would pre-

vent generation capacities from being available on days notified

by RTE are factored into the calculation of the effective capacity

level.

5.1.4.2.4  Accounting for system constraints

In their current form, the rules do not include any specific provi-

sions about accounting for network availability constraints. The

introduction of such a provision, which would entail introducing

a localised incentive into the certification process, has not been

ruled out. However, the complexity of system constraints is such

that the timetable for preparing the rules for the first delivery

year was not compatible with the inclusion of a provision on this

subject.

This issue was nonetheless raised during the consultation.

Two options for taking system constraints into account were

presented:

> The first was based on a pooling of system constraints at the

level of the security factor, with related constraints (unavaila-

bility of networks) being neutralised in the calculation of the

effective capacity level;

> The second was based on the terms of connection contracts

regarding temporary limitations with ex-post verification if

network availability does not meet an operator’s expecta-

tion. RTE favours this second option, as it avoids having the

Value of adequacycriterion = K0 (3h)

Value of adequacycriterion = K1

Value of adequacycriterion = K2

Addition of 100 MWof a specific resource

Addition of X MWof a perfect resource

By iteration, we determine X such that K1 =K2 The specific resource is allocated X certificates for 100 MW

1 2

129

CAPACITY CERTIFICATION / 5

community bear a cost stemming from an inability to remove

power from certain facilities. The guiding principle in the rules

proposed is that obligated parties should have resources to

manage their obligation and not be exposed to costs that are

completely beyond their control.

5.1.4.3 Provision adopted on the calculation of

the capacity level

In compliance with the provisions of the decree and in the light of

the considerations above, the formula for calculating the capacity

level (certified or effective) adopted in the rules takes the form:

CapacityLevel = PP2AvailablePower x K

The K coefficient adopted in the rules applies only to the energy

constraints discussed in § 5.1.4.2.1 and breaks down as follows:

K = Kd x Kw

The Kd coefficient reflects the influence of daily energy constraints

on a capacity’s contribution to reducing the shortfall risk

The Kw coefficient reflects the influence of weekly energy

constraints on a capacity’s contribution to reducing the short-

fall risk

Normative approach

CapacityLevel = HistoricPeakProducibleEnergy x CCtechnology

Chronological summary of the certification process:

For the first two delivery years, the rules adopt specific provi-

sions making it possible to take into account:

> A specific first delivery year (from 30  November 2016 to

31 December 2017 with July and August excluded) enabling

transition to a delivery year matching the calendar year;

> A shorter period between the start of the term and the deli-

very year. The rules directly incorporate the mechanism para-

meters for these two years and certification request deadlines

have been modified accordingly.

Once the mechanism is established, i.e. as of the third delivery

year, the chronology of the certification process will be as follows:

15/01 DY+131/12

A+3 mois

Operationalgenerationcapacities

01/12 DY+2

Transferdeadline

Publication of certification

parameters

15/12 DY+2

Planned generation capacities

Demand response capacities

REBALANCING period

Certificationperiod

01/11 DY-4

01/11 DY-1

01/11 DY-301/01

31/0301/11

DELIVERY YEAR

DY

PERIOD

PP2 PP2

15/02 DY+3

Collectiondeadline

Notificationof effective

capacity level

Imbalancenotification

date

DELIVERY

by month on the basis of a shortfall landscape evaluated seve-

ral years before the delivery year. In this case the PP2 periods

consists of approximately 1,200 hours;

> A “demand-based” approach with PP2 targeting the actual

hours of highest demand during the delivery year. Each hour

of the PP2 peak period is equivalent. This definition results in a

lower number of PP2 hours (between 100 and 300).

5.2  Period covered by capacity certification (PP2)

5.2.1 Period during which the contribution in estimated

Two main approaches were given consideration during the

consultation:

> A “time-based” approach with PP2 being a non-targeted

period defined in advance made up of working days between

November and March. The hours included in PP2 are weighted

130

Figure 58 shows a comparison of the shortfall periods

identifi ed in RTE’s probabilistic supply-demand balance

studies and demand levels during shortfall hours.

Two key conclusions can be drawn from it:

> The hours of highest demand are a good indicator of short-

fall situations. 99% of shortfall hours are contained in the

300 hours of highest demand;

> The 100 hours of highest demand include 94% of the hours

with shortfalls.

The adoption of a targeted period and demand-based approach,

resulting in a PP2 of between 100  and 300  hours during the

delivery year, is thus an appropriate way to estimate capacity’s

contribution to reducing the shortfall risk.

Given the link between contributions to reducing the shortfall risk

and the hours of highest demand, a capacity that is available all win-

ter will make the same contribution to reducing the shortfall risk as

one that is only available during periods of high demand. Both must

therefore receive the same number of capacity certifi cates.

However, their capacity level depends on availability during PP2.

To illustrate the infl uence of PP2 on the volume of certifi cates

allocated to a capacity, the chart below considers two capacities,

one available over 100 hours and one over 500 hours.

The blue curve shows the link discussed above between short-

fall hours and the hours of highest demand. A resource available

in the 200 hours of highest demand has a contribution almost

equivalent to that of a “perfect” resource159 (98% of the shortfall

hours are within the 200 hours of highest demand). The green

and purple curves illustrate the impact of the scope of PP2 on

the volume of certifi cates allocated with regard to the availa-

bility constraint. Since capacity availability is measured over

PP2, capacity that is available during the 200 hours of highest

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0 100 200 300 400 500 600

Shar

e of

hou

rs w

ith

sh

ortf

all

Rank of hours of highest consumption

Figure 58 – Link between shortfall and hours of highest consumption

Hours of highest consumption/Duration of PP2

Red

uct

ion

of s

hor

tfal

l ris

k

1101

201301

401501

601701

801901

1,0011,101

1,2011,301

1,4011,501

1,6011,701

1,8011,901

2,001

0%

20%

40%

60%

80%

100%

Figure 59 – Impact of the duration of PP2 on the contribution calculated for capacity(Source: RTE, WG of 07/02/2013)

Contribution to reduction of shortfall risk according to number of hours of availability

Contribution allocated to a capacity available for 100 hours according to duration of PP2

Contribution allocated to a capacity available for 500 hours according to duration of PP2

159A “perfect” resource is a capacity with no technical constraints and that is available at full power all the time.

131

CAPACITYCERTIFICATION / 5

demand, and thus has a high contribution, will receive fewer

capacity certifi cates if availability is measured over a longer

period (the allocation would only be about 50% with a PP2 of

1,000 hours for example). As such, the certifi cates allocated to

this capacity would not refl ect its contribution to reducing the

shortfall risk.

The bottom line is that the application of a non-targeted (and

therefore long) PP2 period underestimates the certifi cates that

should be allocated to capacity that is available less but may

make a considerable contribution to reducing the shortfall risk.

5.2.2 Consequences of the PP2 period defi ned on the distribution of certifi cates between technologies

As discussed above, the defi nition of the PP2 period can have

major redistributive eff ects between the diff erent types of

capacity, particularly demand response. Indeed, it appears that

demand response capacities are often available during targe-

ted periods: all other things being equal, a longer PP2 period

will reduce the number of certifi cates allocated to a demand

0

2,000

4,000

6,000

0

50

100

150

200

250

0

500

1,000

1,500

2,000

2,500

3,000

0

20,000

40,000

60,000

CCGT

WIND

BM DEMAND RESPONSE

NUCLEAR

Trend in effective availability according to method of defining PP2

2011 2011

2011 2011

Eff

ecti

ve p

ower

(MW

)

Delivery year (Winter)

Figure 60 – Winter 2011/2012 – Comparison of time- and demand-based approaches

 100h of highest demand  200h of highest demand  300h of highest demand

 Winter with weighting [1,8,70,20,1]%  Winter with weighting [2.5,30,55,10,2.5]%  Winter with weighting [5,20,40,30,5]%

response capacity even through its eff ective contribution can

be signifi cant.

A comparison of the demand-based approach targeting the

200  hours of highest demand and a time-based approach

covering the whole winter with monthly weightings linked to

the shortfall probability highlights the impact PP2 has on the

number of capacity certifi cates allocated to each technology.

This impact is illustrated in fi gure 60, which was taken from a

study presented during the consultation on four technologies

characteristic of the French fl eet: nuclear, combined-cycle gas,

wind and demand response.

Choosing a PP2 period not targeted to the hours of highest

demand and weighting availability over the whole winter results

in much less certifi cation of demand response and similar capa-

cities. The eff ective capacity level thus does not refl ect the real

contribution of demand response to reducing the shortfall risk

during the delivery year, regardless of weightings. Conversely,

with a targeted PP2 period, the amount of certifi cates allocated

to demand response refl ects its contribution to security of sup-

ply, without prejudice to generation capacity.

132

Table 3 – Trend in total eff ective availability level

5.2.3 Consequences of the PP2 period defi ned on the variability of certifi cate volumes

Some generators questioned the choice of a targeted PP2

period, citing the underlying risk of instability and saying they

consequently did not have enough visibility to make commit-

ments with regard to availability.

To test this argument, RTE conducted a study that quantifi es the

impact of the choice of the PP2 period on the eff ective capacity

level. This study was based on past availability data and compared

the eff ects of the two approaches (targeted vs. non-targeted) on

the same perimeter, using the same hypotheses. Results are pres-

ented for the fl eet as a whole and for each technology. The eff ective

availability of the generation fl eet was calculated for the years from

2006 to 2011. The fi gure below and accompanying table show the

aggregated results of availability calculations for the period from

2006 to 2011 depending on the PP2 period chosen.

The fi rst conclusion to be drawn from this study is that levels

are consistent with time- and demand-based approaches and

stable over time.

Similar results are obtained with all methods each year and none

can be considered divergent or more volatile than the others:

> Trends are the same, since a drop in the eff ective level of avai-

lability is observed only in the winters of 2008 and 2009, and

the level increases for the other years with both approaches;

Figure 61 – Trend in total eff ective availability level

Delivery year (winter)

80,000

85,000

90,000

95,000

100,000

80,000

85,000

90,000

95,000

100,000

2006 2007 2008 2009 2010 2011

Hou

rs of high

est deman

dW

eighted w

inter

Max DIFFERENCE between methods adopting the same approach 2006 2007 2008 2009 2010 2011

Demand-based 371 105 1,156 713 221 402

Time-based 845 1,326 1,314 1,523 1,751 2,593

Type # PP2 method 2006 2007 2008 2009 2010 2011

Demand 1 100 hours of highest demand 85,124 88,301 94,204 91,841 96,763 98,059

Demand 2 200 hours of highest demand 84,865 88,291 93,574 91,372 96,580 97,667

Demand 3 300 hours of highest demand 84,753 88,197 93,048 91,128 96,542 67,657

Time 4 Winter with weighting [5,20,40,30,5]% 83,228 87,494 91,406 89,217 95,915 96,118

Time 5 Winter with weighting [1,8,70,20,1]% 84,073 88,820 92,720 90,740 97,665 98,711

Time 6 Winter with weighting [2.5,30,55,10,2.5]% 84,029 87,572 91,693 89,600 96,975 97,932

100h of highest demand

200h of highest demand

300h of highest demand

Winter with weighting [5,20,40,30,5]%

Winter with weighting [1,8,70,20,1]%

Winter with weighting [2.5,30,55,10,2.5]%

133

CAPACITY CERTIFICATION / 5

> Orders of magnitude are similar in terms of raw results with

a difference of less than 3%. The maximum difference of 3%

corresponds to the winter of 2008, between methods 1 and 4;

> The standard deviation over the five delivery years is compa-

rable (4 GW effective) whatever the method.

Time- and demand-based approaches can then be compared

based on the choice of parameters:

> With a time-based approach, monthly weightings heavily

affect the effective availability of the fleet. The maximum dif-

ference between the methods {4, 5  and 6} varies between

845 MW (winter of 2006) and 2,593 MW in effective value (win-

ter of 2011). The weighting applied thus has a major impact

on the capacity level. This weighting depends on modelling

choices that can have an arbitrary component. For instance,

during the consultation in the first half of 2013, significant dif-

ferences were observed between evaluations conducted by

RTE and EDF using monthly weightings.

> With a demand-based approach, the choice of the number

of hours in the PP2 period has little impact on the effective

availability of the fleet. The maximum difference between

the methods {1, 2 and 3} ranges between 105 MW (winter of

2007) and 1,156 MW in effective value (winter of 2008). This

low level of sensitivity to the number of hours taken into

account is an advantage of this approach and a major fac-

tor of stability.

5.2.4 Approach adopted in the rules

The rules adopt the “demand-based” approach since it presents

the following advantages:

> It ensures consistency between the contribution to reducing

the shortfall risk and the amount of certificates allocated,

notably for capacity available for shorter periods. If a capacity

is available during peak hours, it will receive all the capacity

certificates to which it is entitled. Peak capacity, and particu-

larly peak demand response, is not penalised and given the

same treatment as base/semi-base load capacity;

> It avoids diluting operators’ responsibilities with regard to the

availability of their capacity: in particular, it guarantees that if

load shedding is required due to the unavailability of genera-

tion capacity during the peak period, some capacity portfolio

managers will necessarily show imbalances;

> It is in keeping with the provision of the decree regarding the

principle of non-discrimination between a reduction in the

amount of the capacity obligation due to load reduction and

the certification of demand response capacity;

> It prevents a potential windfall effect for demand response

capacity that could be certified but then declare

itself unavailable (with regard to the certifica-

tion) during PP1 hours while being activated

during these hours. With a period PP2 spanning

the whole winter and a targeted PP1 period, this

capacity would be double remunerated: it will be

rewarded implicitly for being activated during PP1

hours (leading to a reduction in the capacity obli-

gation) and then recognised as certified capacity

(relating to availability). Even if was not available

during PP1 hours, these hours could carry a very

low weighting with a “time-based” approach160,

meaning it could receive almost the full remune-

ration possible as certified capacity;

> It makes capacity and energy signals consistent.

With a time-based approach, capacity subject

to availability constraints could give priority to

months with a very high weighting rather periods

when supply is actually tight.

The studies conducted also provided some insight into the

comparison of the two approaches (see below). The results sup-

port the choice of a demand-based approach.

5.2.5 Notification of PP2 hours

The decree stipulates that there is to be no discrimination

between a reduction of the obligation and certified demand res-

ponse capacity, implying that the PP1 period must be included

in the PP2 period. This is notably necessary to take into consi-

deration the activation of demand response capacity, either in

the certification or the obligation. The notification system adop-

ted for PP1 days is therefore also for the notification of PP2 days.

A large share of PP2 days (at least 40% and potentially as much

as 100%) will consequently be notified on D-1 at 10:30am.

During the consultation, many stakeholders stressed the need

for the capacity mechanism to address periods of tension

beyond those of high demand to comply with the provision

of the decree relating to peak periods: “the hours of a delivery

year during which the shortfall risk is highest, particularly those

during which national demand is highest.”

Consequently, the notification of PP2 days not included in

the PP1 period will be based on a criterion incorporating

data related to demand and tension on the system. This pro-

vision adds flexibility because the projected shortfall landscape

is not set in stone. To factor in tightness of supply, information

160Note: the “time-based” approach involves defining the winter period as the PP2 peak period. Winter hours are weighted with a probability coefficient reflecting the associated level of risk. With this approach, January alone contains between 50% and 70% of the shortfall risk depending on the models used. PP2 hours are thus determined several years in advance, initially as peak hours (morning and evening peaks) on working days in the winter period. The amount of capacity certificates allocated to a capacity is calculated by multiplying its availability in each winter month by the risk coefficient associated with each month.

134

Stan

dard

dev

iati

on (M

W)

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

2006 2007 2008 2009 2010 2011 Average

Stan

dard

dev

iati

on (M

W)

France BM demandresponse

Wind RoR Hydro Nuclear PV Thermal

0

500

1 000

1 500

2 000

Figure 62 – Variability of eff ective capacity level for France depending on location in time of PP2 days

Figure 63 – Variability of eff ective capacity level for France and per technology depending on location in time of PP2 days (average, minimum and maximum between 2006 and 2012)

  Jan. to March & Nov. and Dec.

  Jan. to March & Nov. and Dec. with max. 5 d in March and Nov.

  Jan and Feb. & Dec.

  Jan. to March & Nov. and Dec.

  Jan. to March & Nov. and Dec. with max. 5 d in March and Nov.

  Jan and Feb. & Dec.

system, RTE will be able to notify PP2 hours as soon as situa-

tions of tight supply are anticipated, i.e. after the network access

deadline time.

5.2.6 Sensitivity of eff ective capacity level to the location in time of PP2 hours

The issue of operators’ visibility on the eff ective capacity level of

their capacities was addressed during the consultation, just as

debates were held about the sensitivity of the obligation to the

will have to be gathered about forecast demand, exchanges

between France and neighbouring countries and capacity avai-

lability. For this purpose, RTE will rely on information gathered

through the programming system. Taking this dimension into

account necessarily puts notifi cation after the economic optimi-

sation of stakeholders’ customer portfolios, which is done after

spot market fi xing. Consequently, PP2 days outside PP1 will be

notifi ed at the latest at 7pm for the following day, leaving at

least 12 hours before the fi rst PP2 hour of the following day. By

using the information made available through the programming

135

CAPACITYCERTIFICATION / 5

location in time of PP1 hours (see chapter 4). Some stakehol-

ders noted that their eff ective capacity level depended in part

on the location in time of PP2, and therefore on eff ective climate

conditions. This could create uncertainty about the amount of

capacity certifi cates operators will receive.

A study was conducted, applying the provisions adopted in the

rules, to test the sensitivity of the eff ective capacity level to cli-

mate scenarios using data from the 2006-2011 period. For each

year, 100 scenarios were considered with diff erent distributions

of PP2 hours, applying 100  consumption scenarios for France

based on the 100 Météo France climate scenarios.

It should be noted that the study overstates the sensitivity we

are seeking to establish. The distribution of PP2 days and the

availability of certifi ed capacities are not independent variables.

Capacity availability depends on demand forecasts and the pro-

jected state of the system, particularly for nuclear power at the

beginning and end of the period. Consequently, if risk realisation

plays out diff erently, generators will adjust the availability of their

capacity accordingly, for instance by postponing scheduled main-

tenance shutdowns. As such, implicitly assuming that the availa-

bility of the capacity certifi ed in 2010 would have been the same

even if weather conditions had been diff erent is an approximation.

The number of PP2 days was set at 25. PP2 days were notifi ed

using two approaches:

> Setting a maximum number of days that could be selected in

March and November;

> Selecting days exclusively in January, February and December.

Figures 62 and 63 show the standard deviation of available

power in France and per technology applying the diff erent

approaches to PP2.

The fi rst conclusion that can be drawn from the study is that the

variability of the capacity level in France is indeed accounted

for primarily by nuclear capacity: the standard deviation of the

capacity level in the nuclear segment corresponds on average

to 90% of the total standard deviation of the total capacity level.

Standard deviations for the hydro and thermal power segments

are nearly three times lower than for the nuclear segment.

Secondly, volatility in the capacity level ranges between 500 and

1,800 MW (between 0.5 and 1.9% of the total capacity level for

France) depending on the provisions adopted for PP2 and the

related signal. By way of comparison, this level of uncertainty is

of the same order of magnitude as the error in demand fore-

casts for the following day during winter peaks.

This study also illustrates the stabilising eff ect of the signal. The

standard deviation decreases by about 20% with a milestone

limiting the number of days in November and March. This stabili-

sing eff ect only has a noticeable impact on the nuclear segment

Nuclear

Max

imu

m a

vaila

ble

pow

er (G

W)

Month

Thermal

November December January February February

60

55

50

45

Nov. Dec. Janv. Feb. March Apr. Nov. Dec. Janv. Feb. March Apr.

25

20

15

10

5

Figure 64 – Trend in average maximum power available on eligible PP2 days

136

and is not constant for all delivery years. Milestones might be

able to attenuate extreme situations but they cannot eliminate

them. The highest variability was seen in the system in 2009,

refl ecting the variability of the actual availability of nuclear capa-

city (standard deviation between 1,100 and 1,500 MW).

These results refl ect the strong seasonality of the availability of

nuclear capacities based on the timing of scheduled shutdowns.

Figure 64 illustrates the change in available power in the nuclear

and conventional thermal segments for the winter of 2010/11;

each dot represents the average over a day, in line with the

methods adopted in the rules (eligible time slot and days).

The availability curve of nuclear capacity is “bell-shaped” and moves

considerably between early November and mid-January (diff erence

of more than 10 GW), whereas the availability of conventional ther-

mal is “fl atter”. The eff ective capacity level of nuclear capacity is

thus much more sensitive than conventional thermal to the num-

ber of PP2 days positioned in November and March.

Some participants in the consultation spoke of the need to sta-

bilise the capacity level via the selection of PP2 days. The idea

was to reduce the weighting of November and March by adding

milestones; some even suggested that no PP2 days should be

selected in these months.

The fi rst point to bear in mind is that the studies cited showed

that these provisions only aff ect the nuclear segment because

of the highly seasonal nature of its availability. And the avai-

lability curve for nuclear capacity must not be considered an

exogenous factor. Operators can adapt the availability of their

capacities on the basis of their consumption forecasts and the

state of the system, particularly at the beginning and end of the

period (for instance by rescheduling shutdowns). Studies based

on actual results therefore overestimate the volatility of capaci-

ties, including nuclear capacities.

Secondly, it is essential that the period during which PP2 days

are selected cover all shortfall risk periods. Diff erent assess-

ments of the shortfall landscape were presented during the

consultation, and all showed a shortfall risk in November and

March. Depending on the estimate used, these months contain

between 2 and 10% of shortfall situations in probabilistic supply-

demand balance studies; the fi gure can rise to almost 50% loo-

king at the records of degraded modes for the supply-demand

balance on the balancing mechanism. The proposal to exclude

March and November from the period during which PP2 days

are selected was therefore not adopted in the rules.

For illustration purposes, the historical distribution of EJP days,

decided by EDF, was analysed from 2004-05 to 2011-12.

The analysis shows that on average, 30% of EJP days were acti-

vated in November and March, with highs of more than 40% in

certain years and a minimum of 10% for all years. A signal sub-

ject to energy constraints (22 days for EJP) requires a conside-

rable volume in November and March for the management of a

portfolio that is preponderant in the French power system.

5.2.7 Provisions adopted in the rules on PP2

The rules defi ne the PP2 peak period as a targeted period corres-

ponding to a limited number of days (between 10 and 25) and a

time slot defi ned applying the “demand-based” approach adopted.

Consistency between PP1 and PP2 is ensured by the fact that

PP1 is included in PP2 (all PP1 hours are PP2 hours). Because PP1

Figure 65 –Distribution of EJP days between 2004-2005 and 2011-2012

0%

10%

20%

30%

40%

50%

Nov. Dec. Jan. Feb. March

 Maximum  Minimum  Average

The rules proposed include a provision limiting the number of PP2 days that can be activated in November and March (maximum 25% of total). This regulates the variability of the capacity level inthe nuclear segment and therefore in the system while ensuring that there are still enough PP2 days to cover most potential shortfall and tight supply situations in these months. The studies pre-sented above give an estimate of the eff ects of this provision (20% attenuation of the variability associ-ated with the location in time of PP2 days).

137

CAPACITYCERTIFICATION / 5

and PP2 volumes are comparable, there is no signifi cant devia-

tion from the principle of non-discrimination between certifi ed

demand response capacity and a reduction of the obligation.

Notifi cation of peak days on D-1 gives stakeholders more visibi-

lity while also allowing information about anticipated situations

of tight supply to be taken into account, which will make it easier

for the mechanism to be adapted going forward (notably to the

changes resulting from the integration of renewable capacities).

Lastly, milestones were introduced in response to requests

by several stakeholders, the goal being to stabilise the capa-

city level for France, and particularly for the nuclear segment,

through the PP2 days selected.

1. The PP2 period corresponds to the time slots [07:00; 15:00[ and [18:00; 20:00[ (i.e. 10 hours per day) of the days notified by RTE.

2. All days notified for PP1 are days notified for PP2 (inclusion of PP1 in PP2).

3. PP2 days are notified on D-1: the PP2 days that are also PP1 days will be notified before 10:30am; PP2 days outside PP1 will be noti-fied at 7pm at the latest.

4. The signal is based mainly on a demand cri-terion (days when demand is expected to be highest) and factors in information about anticipated tension in the system.

5. Between 10 and 25 PP2 days are notifi ed with no more than 25% of them in March and November.

5.3.2.1.1 Kd chart

The Kd chart for a delivery year is based on supply-demand

balance simulations for the delivery year focused on evaluating

the contribution to reducing the shortfall risk of a resource with

a daily energy constraint on a time slot of a PP2 day.

The Kd chart for a delivery year is established by RTE and speci-

fi ed in the rules. This chart is known to operators from the start

of a capacity mechanism term and remains stable throughout.

The Kd chart for the fi rst delivery year is shown below:

5.3 Calculation of the capacity level

5.3.1 Available power of capacity

Available power corresponds to the power that can be activated

during PP2. Data can be gathered about available power either:

> Through a separate system for collecting capacity availability

data that is not directly linked to the capacity mechanism rules;

> Or through a system developed by RTE to fulfi l its role and

responsibilities with regard to implementing the rules.

5.3.2 Determination of the coeffi cient to refl ect the technical constraints of capacity (K)

The formula used to calculate the parameter K is as follows:

K = Kd x Kw

5.3.2.1 Determination of Kd modelling daily energy

constraints

The Kd parameter refl ects the infl uence of the energy constraints

associated with a capacity on its contribution to reducing the

shortfall risk.

The value of Kd is determined from a chart (Kd chart) in force for

the delivery year and from the parameters declared by the ope-

rator (for the calculation of its certifi ed capacity level) or measu-

red (to calculate its eff ective capacity level).

Figure 66 – Illustration of the Kd chart

0%

20%

40%

60%

80%

100%

0 1 2 975 643 8 10

Valu

e of

Kd

(%)

Value of Nd (hours in the PP2 time slot)

138

5.3.2.1.2  Parameters used in the calculation of Kd

The parameters used in the calculation of Kd are as follows:

> EPP2d: Maximum energy activatable on the PP2 time slot

> MaxP: Maximum available power of the capacity

An Nd coeffi cient is calculated from this data as follows:

Nd = min ( EPP2dMaxP

; 10 )The Nd coeffi cient corresponds to the number of hours capacity

can be activated at MaxP per day on the PP2 time slot.

Based on these data and the Kd chart, an operator can estimate

the value of the Kd coeffi cient associated with its capacity.

5.3.2.1.3  Daily constraint and available power

As indicated above, the available power of a capacity corres-

ponds to the power that can be activated on the PP2 time slot.

The daily constraint refl ects the maximum energy that can be

activated on the PP2 time slot.

On a PP2 day, if an operator has activated the capacity and the

energy generated corresponds to the maximum energy decla-

red, it has fulfi lled the commitment in its certifi cation contract.

It is therefore necessary to ensure that the energy constraint is

not counted twice.

In this specifi c case, the formula PP2Available-Power x Kd is replaced by PP2Activation.

5.3.2.2 Determination of Kw modelling the weekly

energy constraint

The value of the Kw coeffi cient is also determined using a chart

(Kw chart) applicable to the delivery year and parameters decla-

red by the operator (for the calculation of its certifi ed capacity

level) or measured (to calculate its eff ective capacity level).

5.3.2.2.1  Kw chart

The Kw chart for a delivery year is based on supply-demand

balance simulations for the delivery year focused on evaluating

the contribution to reducing the shortfall risk of a resource with

an energy constraint over several consecutive days of the deli-

very period.

This chart is known to operators from the start of a capacity

mechanism term and remains stable throughout.

The Kw chart adopted in the rules for the fi rst delivery year is

shown below:

5.3.2.2.2  Parameters used in the calculation of Kw

The parameters used in the calculation of Kw are as follows:

> EPP2d mentioned for the calculation of Kw

> wE: energy that can be activated over fi ve consecutive wor-

king days on the time slots [07:00-15:00[ and [18:00; 20:00[

The approach diff ers however from the one used for Kd in the

sense that data is not measured over PP2 days but monitored

more broadly over the delivery period.

An Nw parameter is calculated from this data as follows:

Nw = min ( wEEPP2d

; 5 )Nw corresponds to the number of working days during which the

capacity can be activated taking into account its daily constraint.

Based on these data and the Kw chart, an operator can estimate

the value of the Kw coeffi cient associated with its capacity.

5.3.2.3 Illustration of how the Kd coeffi cient is

determined for capacity

The information below is provided purely for illustration

purposes.

For capacity with available maxP of 100 MW, maxE,d of 400 MWh

and no energy constraint (meaning it can be activated every day

of the delivery period):

Nd = 400100

hours per day at maxP during hours of the PP2 time slot

The value of the Kd associated with a capacity is calculated as:

Kd (4) = 70%

Figure 67 – Illustration of the Kw chart

0%

20%

40%

60%

80%

100%

0 1 32 4 5

Valu

e of

Kw

(%)

Value of Nw (number of consecutive days)

139

CAPACITYCERTIFICATION / 5

0%

20%

40%

60%

80%

100%

0 1 2 975 643 8 10

Valu

e of

Kd

(%)

Value of Nd (hours in the PP2 time slot)

Figure 68 – Determination of the Kd coeffi cient for a capacity

5.4  Certifi cation requests

Certifi cation requests can be fi led for capacity once the capa-

city mechanism term starts, i.e. when the register is opened for

the delivery year in question following the publication of the

mechanism parameters (possibly including updated certifi ca-

tion charts); requests can be fi led for planned capacity based on

a predefi ned specifi c technical milestone.

5.4.1 Defi nition of capacity

5.4.1.1 Capacity status

Under the terms of the decree, deadlines are set for certifi cation

requests “based on the technical characteristics of the capacity

and, for new capacity, based on the status of the project” (para-

graph I of article 8 of the decree). The rules must therefore make

it possible to defi ne the technical characteristics to be taken into

account for setting certifi cation request deadlines.

The status of capacities (existing or new) also has an impact on

the security deposits required. The decree specifi es that “the

certifi cation contract includes […], where appropriate, especially

for new capacities, the amount of the security deposit to be pro-

vided by the operator” (paragraph III of article 9 of the decree).

The rules factor in this requirement that security deposits be

provided for planned capacity for each delivery year for which

certifi cation is requested. Security deposits are only returned

when the capacity is brought into service.

5.4.1.1.1 Existing capacity / new capacity

Under the terms of the decree, existing capacity is capacity that

is included within a certifi cation entity for a future, present or

past delivery year. New capacity is capacity that has never been

part of a certifi cation entity.

5.4.1.1.2  Operational capacity/planned capacity 

Capacity can be certifi ed several years before the delivery year.

It is possible for capacity to be considered existing capacity, as

defi ned in the decree, but still in the project phase. The terms

above (existing capacity/new capacity) are applied to the certi-

fi cation process, and particularly to the certifi cation entity. They

do not specify whether the capacity exists or not. For instance,

a capacity may be certifi ed for the fi rst time three years before

becoming operational; it is in this case considered existing capa-

city for the following delivery year, but is still planned capacity

until industrial operations begin.

A distinction must therefore be made between capacities that

are operational and those still in the project phase. All capacity

that is operational for a delivery year must have a certifi cation

contract for that delivery year.

5.4.1.2 Nature of capacities

It is essential that the addition (new capacity) and removal

(decommissioning) of capacities be properly accounted for in

140

the mechanism. The mechanism is intended to achieve the level

security of supply desired by public authorities, but it must not

create an entry barrier for new capacity or reward “phantom”

capacity.

Two risks relating to planned capacities have been identified:

> Projects might not be completed: the risk is that projects

may be postponed or cancelled even though the capacity is

necessary to guarantee security of supply. This creates a risk

of default by an operator that has sold certified capacity;

> If planned capacities are not taken into account, then the

investment signal will be meaningless.

Essentially, there are two possible approaches to this issue: one

involves certifying all planned capacity declared, with significant

financial guarantees required in exchange; the second involves

physical verifications of capacity, in which case the financial gua-

rantees demanded can be lower since the risk is lower.

5.4.1.2.1  Generation capacity

5.4.1.2.1.1 Operational generation capacity

Using the definitions given at the beginning of this section, any

generation site covered by a network access contract or calcula-

tion service contract is considered operational generation capa-

city. For the first delivery year, any generation site with either

type of contract in force as of 1 November 2014 is also counted

as existing generation capacity.

Existing generation capacities will be certified once the mecha-

nism term starts, and this will provide additional information

about the state of the fleet, above and beyond what is included

in adequacy studies based on the declarations made by genera-

tors (a certification request indicates that the generator plans to

be present during the delivery year).

5.4.1.2.1.2 Planned generation capacity

As discussed above, there is often uncertainty about when plan-

ned capacities will become operational. With this in mind, the

rules adopt a proposal that sets the certification deadline as

close as possible to the delivery year, to ensure a high probability

that the underlying capacity project will be completed.

5.4.1.2.2  Demand response capacity

The Energy Code stipulates that “certification requests must be

submitted by operators for all demand response capacity” (Art.

L321-16). As written, this provision is difficult to put into prac-

tice. Technically, any consumption site with a circuit breaker can

reduce its load, but all consumers cannot be obliged to request

certification.

A proper definition of “demand response capacity” must there-

fore be used for the specific purposes of certification: demand

response capacity is a demand response capability (flexibility)

that has been certified as such. Applying this principle, it is pos-

sible to accurately define operational demand response capa-

city and planned demand response capacity.

5.4.1.2.2.1 Operational demand response capacity

Operational demand response capacity is an existing extraction

site or group of extraction sites constituting a certification entity

for a given delivery year.

The operator of operational demand response capacity can only

declare certification parameters (available power and data used

for the calculation of K) on the basis of the extraction sites that

are affiliated with it when the certification request is made.

5.4.1.2.2.2 Planned demand response capacity

Planned demand response capacity refers to the planned peri-

meter of extraction sites declared by the capacity operator and

constituting a certification entity for a given delivery year.

The operator of planned demand response capacity can declare

certification parameters (available power and data used for the

calculation of K) on the basis of the extraction sites affiliated with

it when the certification request is made and its forecasts regar-

ding future changes in the perimeter.

Certification of planned demand response capacity requires a

security deposit.

5.4.1.3 Aggregation methods

5.4.1.3.1  Aggregation thresholds

The rules specify how different capacities can be aggregated

within a certification entity. For aggregated capacities, only

one certification request is filed and one certification contract

issued.

This is in keeping with the provision of the decree stating that

“The methods of certifying and verifying capacities making a

limited contribution to security of supply be adapted accor-

dingly” (paragraph 1 of Art. 10). The decree specifies that

“requests for certification of such capacities can only be made

in aggregated form” (paragraph II of Art. 10). In the rules, the

141

CAPACITY CERTIFICATION / 5

individual volume of capacities is adopted as the technical

characteristic used to determine to which capacities these

provisions apply.

Capacities with a power rating of less than 1 MW must be aggre-

gated with one or more capacities of the same type (generation

or demand response) to constitute a certification entity with

total power of at least 1 MW.

Some stakeholders indicated during the consultation that they

needed to be able to aggregate capacities beyond the sprea-

ding of imbalances ensured by capacity portfolio manager peri-

meters. The idea is to take into account technical characteristics

such as rotating activations of individual capacities for demand

response or mutual influence for hydro capacities.

A threshold was therefore introduced in the rules. Aggregation is

possible for capacities with individual power of at least 1 MW and

no more than 100 MW.

Capacities with power ratings of 100 MW or more must be certi-

fied individually: every capacity with a power rating of 100 MW or

more must form its own certification entity. The same 100 MW

threshold is applied in EU regulation 543/2013 of 14 June 2013,

the “transparency regulation”.

The minimum threshold of 1  MW is consistent with the target

level of detail of offers on the balancing mechanism for 2016

(the threshold is in the process of being lowered from 10  MW

to 1 MW).

5.4.1.3.2  Capacity aggregation perimeter

The Energy Code stipulates that certification requests must be

filed for all generation and demand response capacities. Under

the rules, aggregated sites forming part of the same certifica-

tion entity can be connected to different networks, in keeping

with the work being done to update the balancing mechanism

and eliminate technical barriers to aggregation. This provision

means that RTE must centralise the certification data for these

sites. It avoids segmenting capacities based on the system

operators with which they are affiliated, and thus an external

constraint serving no economic purpose for operators.

The certification of certification entities comprising sites

connected to different networks, together with a mandatory

aggregation threshold of 1 MW, ensures that capacities partici-

pate. It reduces the risk of overcapacity that could arise if some

capacities were not taken into account.

5.4.2 Certification deadlines

The certification deadlines set represent a compromise between

two contradictory goals:

> One was to give stakeholders as much visibility as possible on

the future state of the system. This would imply setting the

certification request deadline well ahead of the delivery year;

> The other was to factor in the maximum amount of capacity

that can be activated, including in the short term, to avoid the

extra cost of building new capacities that are not needed to

achieve the desired level of security of supply.

5.4.2.1 Existing generation capacity

The deadline for requesting certification of existing generation

capacity depends on whether it is already operational or in the

project phase:

> Existing generation capacities that are operational must ask

to be certified by 1 November of DY-3 (i.e. three years before

the delivery year);

> Existing generation capacities in the project phase must ask

to be certified by 1 November of DY-1 (i.e. one year before the

delivery year)

For existing generation capacities that are operational, setting the

deadline three years before the start of the delivery year may seem

like a constraint in that operators must submit availability forecasts

for their capacity. But the rebalancing system adopted eases this

constraint. Players must also have sufficient visibility on projected

capacity levels for the market to function properly (see chapter 7).

Figure 69 - Illustration summarising the aggregation thresholds adopted in the rules

Aggregation possible

Aggregation compulsory

1 MW threshold

100 MW threshold

No aggregation possible

Volume of capacity unit (MW)

142

For this reason, three years before the delivery year, system capaci-

ties will either be certified and recorded in the capacity register or

considered absent and ineligible to participate in the mechanism at

a later date (they will have been required to submit an irrevocable

closure notice). These procedures are a powerful tool for monito-

ring market manipulation and can be compared to some measures

applied in North American capacity markets, where the behaviours

of existing capacity during capacity auctions are closely monitored.

Specific procedures are nonetheless being planned for capacities

that are in the process of being mothballed (see § 5.4.3.2).

The difference between the amount of capacities in the register

and the forecasts published by RTE relating to the total certificates

required for all stakeholders to meet their obligation will give opera-

tors valuable insight for their forecasts on situations of tight supply.

5.4.2.2 Demand response capacity

The deadline to request certification for demand response capa-

city is set at the beginning of the delivery period.

Demand response capacities are given more flexibility to take

into account i) the fact that they can be developed or removed

shortly before the start of the delivery period, and ii) the fact that

extraction sites have less visibility on their order books and thus

their ability to adjust their consumption. This flexibility also helps

put into practical application the provision in article 13 of the

Brottes Act of 15  April 2013 stating that, if costs are the same,

priority should be given to demand response capacities.

5.4.2.3 New capacity

5.4.2.3.1  Planned capacity

An operator of a capacity in the project phase can request to

have it certified up to two months before the beginning of the

delivery period, i.e. up to 1  November of DY-1. For generation

capacities, the connection agreement must also be signed.

5.4.2.3.2  Operational capacity

Requests to certify new operational capacity must be submitted

within two months following the commissioning date and two

months before the beginning of the delivery period.

5.4.2.4 Overview of provisions adopted for certification

request deadlines

Once the system is established, i.e. as of the third delivery year,

the certification request deadlines will be as follows:

Summary of certification request deadlines

Generation Demand response

Operational capacity 2 months before the start of the delivery period in DY-3, i.e. 1 November DY-3

2 months before the start of the delivery period, i.e. 1 November DY-1Planned capacity 2 months before the start of the delivery

period, i.e. 1 November DY-1

The rules include specific certification request deadlines for the first two delivery years:

> For the first delivery year

> For the second delivery year

Generation Demand response

Operational capacity 1 November 201531 August 2016

Planned capacity 31 August 2016

Generation Demand response

Operational capacity 31 December 201531 October 2017

Planned capacity 31 October 2017

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CAPACITY CERTIFICATION / 5

5.4.3 Withdrawals of capacities

The way a mechanism accounts for “withdrawals” of capacities is

key to its performance. This is especially important for France, given

the situation described in section 1.2.3 of this report: the introduc-

tion of a capacity mechanism in France is seen as a means of regu-

lating the shift from the historical situation characterised by excess

capacity to a new configuration characterised by risks that the

security of supply criteria defined by public authorities may not be

met. The capacity mechanism will be implemented at a time when

some operators are considering shutting down or mothballing cer-

tain facilities, but could reconsider in the light of the value of certi-

ficates on the capacity market. The way in which units that could

otherwise be shut down temporarily or for good are integrated into

the capacity mechanism is therefore all-important.

The specific question of the fate of capacities that have already

been mothballed was also addressed during the consultation.

These capacities could indeed be fired up again if a system need

was identified, and it could cost less to bring them back into ser-

vice than to develop new ones. In the meantime, temporary shu-

tdowns could be appropriate if market prices are low (operators

save on some operating costs when capacities are mothballed).

Improper management of the provisions applicable to these capa-

cities could disrupt the functioning of the market, or even lead to

behaviours constituting manipulation. If it was possible for any ope-

rator to decline to participate in the mechanism initially because

it might mothball its capacities, the system could be vulnerable to

“capacity retention” behaviours - with some operators voluntarily

drying up supply to artificially inflate the price. Even though capa-

city certificate trading will be closely monitored when the mecha-

nism is in place (see chapter 7), the rules governing the mecha-

nism’s functioning must protect the community from these types

of behaviours by making them visible and inefficient.

5.4.3.1 Closure notices

The first rule governing “withdrawals” involves requiring closure

notices for capacity to not participate in the mechanism. Prepa-

red by operators, these notices specify the duration of the clo-

sure, which must cover at least the delivery year considered and

at least three years total for generation capacities and at least

one year for demand response capacities.

This provision is in keeping with the decree, which stipulates that

all existing capacities, whether generation or demand response,

must either request certification or submit a closure notice by

the certification deadline. Capacity for which a closure notice

has been filed for a delivery year is no longer eligible to be issued

capacity certificates: it is definitively excluded from the mecha-

nism for the current year and at least the next two years. The pro-

vision thus incentivises capacity operators to establish forecasts

for their capacity and convey this information to the market; it

makes strategies involving holding back supply citing potential

closures less efficient since, for the capacity in question, opera-

tors cannot take advantage of the price increase their retention

strategy could cause. Moreover, the transparency and monitoring

measures discussed in chapter 7 of this report ensure that any

capacity retention strategy implemented by an operator with

several capacities will be detected and sanctioned.

5.4.3.2 Mothballed capacities

Given the specific characteristics of the French security of sup-

ply landscape, a special system has been introduced for moth-

balled capacities. Under this system, an operator can participate

in the mechanism by using the rebalancing procedure to buy

or sell the corresponding capacity certificates if it provides the

Energy Regulatory Commission with prior notice and specific

documentation, in the format specified in the rules. In concrete

terms, mothballed capacity can participate in the mechanism

by being reactivated between the certification deadline and

the delivery year (in a sense, it has an option to participate in

the mechanism). Likewise, a decision can be made to mothball

capacity between the certification date and the delivery year.

To participate in the capacity mechanism, the operator of capa-

city that has been mothballed must request certification by the

certification deadline, declaring a certified capacity level equal

to 0. If, based on market conditions, the operator subsequently

decides to reactivate the capacity, it must rebalance upward.

There are no costs associated with rebalancing before the

start of the delivery period (except the cost of the certification

request), as explained in the next chapter.

Basically, an operator can decide to mothball a facility after the

certification deadline by rebalancing back to zero. It will in this

case have to return the amount of capacity certificates corres-

ponding to the capacity initially certified through the procedure

outlined in the next section.

In both cases described above - if certification is requested or

the capacity level is rebalanced back to zero - operators must

submit documentation explaining the technical and economic

reasons and specifying how long it would take for the capacity to

be reactivated. This documentation is sent to the Energy Regu-

latory Commission, which is charged with overseeing markets

144

The certification procedures adopted make operators res-

ponsible for imbalances between the level of availability they

indicate when certifying their capacity and the effective availa-

bility of their facilities verified during the delivery period. Such

an accountability system only makes sense if operators have

options to manage the risk. Rebalancing is one tool at their dis-

posal: as the delivery year approaches, operators will have more

accurate information about the future availability of their facili-

ties, and by rebalancing they can modify the reference used to

calculate their imbalance.

The procedures involved in rebalancing are thus a core aspect

of the mechanism’s functioning: the more onerous rebalan-

cing is, the more committed operators will be to the availability

forecasts provided on the certification deadline (three years

before the start of the delivery year for generation capacity);

conversely, if there was no cost involved in reba-

lancing, then operators would not be bound by

the availability forecasts submitted ahead of time,

and the information originally recorded in the

register may be of less value, which is why appro-

priate transparency and oversight measures are

necessary.

by article L. 131-2 of the Energy Code. In sum, the procedures

for entering and exiting the mechanism are tightly regulated.

In practice, the capacity mechanism can significantly influence

operators’ decisions about mothballing or reactivating certain

facilities. And these decisions impact all stakeholders, given the

key role they play in shaping the market price for all capacity (this

effect is notably visible in North American markets). As a result,

maximum transparency is required about the amount of capacity

mothballed. This is why the rules stipulate that specific informa-

tion will be included in the certified capacity register about the

number of facilities mothballed and their historical capacity levels.

All operators should be able to use this information to determine

how many capacity certificates might be returned into the system.

5.4.4 Certification fees

Several options are possible for invoicing certification fees: they

can be calculated per MW certified, per certification entity, based

on the number of sites, etc. With the industrialisation of the cer-

tification process, most costs will correspond to operational

maintenance costs for IT systems. The number of sites or certifi-

cation entities is thus not a discriminating factor: the number of

certificates is what counts.

The rules therefore stipulate that the scale will be defined

in euros per MW certified. A different approach to invoicing

(for instance indexation to the number of sites) would have

been unfavourable for aggregation, and this would have gone

against the objective of giving priority to demand response

defined by publication authorities in the Brottes Act161. It

would also have been detrimental to new entrants with smal-

ler capacities.

Certification fees are also set in the rules. The values proposed

are 6 euros per MW certified for RTE and 57 euros/MW for distri-

bution system operators.

161Article 13 of this act, now article L. 335-2 of the Energy Code, affirms that “At equal cost, [the capacity mechanism] gives priority to demand response capacity over generation capacity.”

5.5 Rebalancing

5.5.1 The rebalancing process

Rebalancing is the mechanism that ensures consistency

between the market and the physical reality. The rebalancing

mechanism proposed allows an operator to submit a rebalan-

cing request as soon as a contingency occurs that impacts its

effective capacity level. The price of rebalancing must incenti-

vise operators to take action as soon as they observe a discre-

pancy between their expected effective capacity level and their

certified capacity level. The mechanism thereby guarantees that

capacity supply in the market corresponds at all times to the

best estimate of the effective capacity level.

The rules define rebalancing as the process by which a capacity

operator modifies the capacity certification parameters it decla-

red, resulting in a fresh certification of the capacities in question

(in other words a new certification contract is established) which is

recorded in the certified capacity register for transparency’s sake.

There are two types of rebalancing:

> Upward rebalancing, resulting in the issue of new capacity

certificates;

> Downward rebalancing, after which capacity certificates are

returned.

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CAPACITY CERTIFICATION / 5

Rebalancing requests are accepted between 1  January of year

DY-4 and 15 January of year DY+1. The capacity portfolio manager

submits a rebalancing request to the transmission system ope-

rator for a capacity within its perimeter. Rebalancing requests

generally include:

> A new certification application with updated technical

parameters;

> The signed consent of the holder of the certification contract

for the capacity;

> Documentation of technical justifications;

> For capacities with certified capacity levels exceeding 100 MW,

a declaration of change in parameters.

Rebalancing requests may also be submitted for modifications

resulting from the constitution of demand response capacity

(change in the perimeter of the extraction sites covered).

5.5.2 Financial consequences of rebalancing

It is proposed in the rules that rebalancing be free of cost

between the start of the mechanism term (four years before the

start of the delivery period) and the start of the delivery period

and then rise incrementally after that. This choice is all-impor-

tant in determining how the mechanism will function: in sum,

the projected capacity level declared by an operator with its ini-

tial certification request is not binding and may be modified over

the following three years with no penalty. If its availability fore-

casts change during these three years, an operator will only pay

the transaction costs associated with rebalancing to modify its

declaration, which is what makes the procedure efficient. Many

generators and demand response operators requested this type

of flexibility during the consultation.

5.5.2.1 Absence of rebalancing costs before the delivery

period starts

As indicated above, the absence of rebalancing costs before

the delivery period begins has a major advantage: the certified

capacity register is not “set in stone” several years in advance,

nor is the certificate price that will be calculated on this basis.

This ties back in with the general debate discussed in chapter

3 about the compromise between the stability and accuracy

of the mechanism signals: while “closing” the register several

years ahead of time would certainly afford more visibility on

the capacity price, the economic value of the signal would

be reduced since it would not factor in information about the

projected supply-demand balance that becomes available

between the start of the term and the start of the delivery

period.

This choices makes it essential to guarantee a high level of

transparency with regard to the registers and systematic

monitoring of the market by the competent authorities. The

measures adopted, which are discussed in more detail in

chapter 7, appear sufficient to prevent operators from sub-

mitting frivolous initial declarations that could impact the tru-

thfulness of the market and interfere with price formation: any

strategy involving the deliberate declaration of projected avai-

lability that does not match up with historical levels or com-

parable capacities will easily be spotted by other stakeholders

and CRE. And with the procedures for submitting rebalancing

requests adopted in the rules, operators must systematically

justify their requests, which provides an additional verification

tool for relevant authorities to use.

PP2

Start of term(01/01/DY-4)

Rebalancingcost

Zero rebalancing cost Progressive rebalancing costaccording to numberof PP2 days elapsed

Start of deliveryperiod

(01/01/DY)

End of deliveryperiod

(31/12/DY)

PP2

Figure 70 – Cost of rebalancing depending on timing

146

5.5.2.2 Progressively increasing imbalance

settlement prices after the delivery period starts

Rebalancing guarantees that market signals are

consistent with the physical situation. It must be

possible for information about contingencies, inclu-

ding those that arise during the delivery period, to

be conveyed to the market through rebalancing.

This is why rebalancing is authorised until the end of

the delivery period.

However, it does not make sense for the cost of

rebalancing to be nil as the delivery period begins.

In order to give stakeholders incentive to commu-

nicate any new information they have about their effective

capacity level to the market as quickly as possible, rebalancing

must take into account the value associated with the timing of

rebalancing requests. It is therefore proposed that the rebalan-

cing price will increase progressively over the delivery period,

as PP2 days elapse. For a same contingency, an operator that

rebalances earlier will be subject to a lower settlement than one

that rebalances later.

To encourage stakeholders to accurately disclose their imba-

lance situations, the rebalancing price must be defined in such a

way as to provide an incentive to opt for rebalancing rather than

a settlement and to rebalance as soon as a contingency arises

affecting a capacity level.

The desired incentive structure can be visualised using a simple

example. The situation of a capacity portfolio manager with a

negative imbalance of ΔV<0 that waits for a settlement is com-

pared with that of a stakeholder that rebalances.

When the capacity portfolio manager waits for the settlement,

the cost associated with its imbalance is:

CostImbalance settlement

= – ∆V x (1 + K) x MarP

If the stakeholder rebalances, it must buy back the missing

certificates on the market at the MarP price (or, if it has not

yet sold them, this will represent its cost of opportunity) and

then rebalance the amount ∆V. The total cost for this stake-

holder is:

CostRebalancing

= – ∆V x MarP + I∆VI x Crebal

To ensure that rebalancing is more advantageous regardless of

the market price during a given delivery year, the rebalancing

cost must be structured in the same way as the imbalance sett-

lement price for capacity portfolio managers, i.e. around the

market price. It is therefore proposed that:

Crebal

= krebal

x MarP

To guarantee that the CostImbalance settlement is always

higher than the CostRebalancing, it is therefore necessary that:

krebal

< K

This result is illustrated below:

Initial situation

Certifiedcapacity

levelEffectivecapacity

level

∆V∆V x (1+K) x marP

-∆V x (1+K) x marP -∆V x (1+krebal.

) x marP

x marP x krebal.

x marP∆V ∆V

Imbalance settlement Rebalancing

RebalancingPurchase ofcertificates

on the market

+

Figure 71 – Illustration of relationship between rebalancing and imbalance settlement

162These principles are without prejudice to changes made subsequently to the balancing mechanism in application of the Network Code currently being drafted in application of EU Regulation 714/2009 of 13 July 2009.

163This is a legal requirement for generators connected to the public transmission system and optional for others.

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CAPACITYCERTIFICATION / 5

Formulaefordeterminingthesettlementforrebalancingbyacapacityportfoliomanager

The amount of the settlement associated with rebalancing by a capacity portfolio manager is calculated with the following

formula:

SettlementRebalancing,CPM = ∑ Volume

Rebalancing,request x UnitPrice

request

The amount of a rebalancing request is the diff erence, in absolute value, between the certifi ed capacity level as of the rebalan-

cing request date (datereauest

) and the capacity level shown in the rebalancing request. It is calculated as follows:

VolumeRebalancing,request

=

I Certifi edLevelcapacity

(daterequest

) – CapacityLevelrequest I

The unit price of a settlement for a rebalancing request depends on when it is submitted. It is calculated as follows:

UnitPricerequest

(daterequest

) = rmP x KDY

x NbPP2daysnotifi edDY(daterequest)

NbPP2daysnotifi edDY(FPL)

> rmP: reference market price used to determine the unit price for the imbalance settlement (see chapter 6);

> KDY: The incentive coeffi cient K for the delivery year used for settlements (see chapter 6);

> NbPP2daysnotifi edDY

(d): Number of PP2 days notifi ed for the delivery year between the start of the delivery period and the

request date d.

A unit price of zero is thus applied to settlements for rebalancing requests submitted before the date the delivery year begins.

compliant rebalancing

requests,CPM

5.6 Collection of data required to calculate effective capacity level

Since declarations are the cornerstone of the certifi cation pro-

cess under the approach adopted, the eff ective availability of

capacities must be systematically verifi ed (along with the other

parameters used). This verifi cation process necessarily requires

going through appropriate channels to systematically collect

data that can attest to the availability of capacities. This is one of

the reasons why mechanisms that remunerate available capa-

city (rather than installed capacity), which are economically pre-

ferable, are sometimes considered costlier to implement.

It is easy to calculate the availability of generation and demand

response capacity on power systems organised according to a

mandatory pool scheme: North American capacity mechanisms

(PJM, New England, New York) are for instance organised around

a pool structure in which all transactions must be either centra-

lised or reported to the system operator. This type of scheme is

not generally not used in Europe when a separation has been

created between the functions of the network operator and the

day-ahead market operator: specifi c procedures for verifying

availability must in this case be implemented.

However, through the balancing mechanism, France already has

a means of gathering much data that can attest to the availabi-

lity of facilities, whether they are connected to the transmission

or distribution networks. In other words, the French balancing

mechanism is not just a venue for activating energy and making

the adjustments necessary to guarantee equilibrium in real time;

it is also used to verify the availability of each facility connected

to the public transmission system and of many units connec-

ted to the public distribution systems to evaluate the operating

margins of the system162. This unusual organisation is centred

round a programming process under which generators163 report

148

their technical constraints and dispatching schedules to RTE

one day ahead at 4pm and declarations are regularly updated

after that through a series of rebalancing gates. The advantage

of this system is that available reserves can be better evaluated,

allowing the system operator to fine-tune its efforts.

Relying on the balancing mechanism to collect data about

availability and carry out verifications would thus be an obvious

option in France, since the mechanism exists and has proved

its worth. This organisational structure would save on costs

that would otherwise be generated by the implementation of

new verification measures. The data collection and verification

mechanism RTE proposes would thus rely whenever possible

on the balancing mechanism, in the interest of technical and

economic efficiency.

As regards the explicit certification of demand response capacity,

extensive discussions were held about how to gather information

about capacity availability. Here again, it would be possible to leve-

rage existing systems, notably the NEBEF mechanism, through

which activated demand response capacity can already be eva-

luated a day ahead, and it could be expanded to allow information

to be gathered about the availability of non-activated NEBEFs.

Other data will also have to be gathered through ad hoc mecha-

nisms (maximum daily energy that can be activated during PP2

peak hours, maximum weekly energy) that will cost less to create

if they are designed as extensions of the balancing mechanism.

5.6.1 Linking of certification entities with BM and NEBEF entities

With the chosen option of using existing systems to collect and

verify data about capacities, the links between the aggregates

used for certification purposes in the capacity mechanism (cer-

tification entities) and existing procedures for identifying facili-

ties and sites on the balancing mechanism (balancing entities)

or the participation of demand response in the market (NEBEF)

(demand response entities) must be properly defined.

The rules must also seek to reduce any potential

entry barriers and plan a specific regime for demand

response from the outset.

The capacity mechanism rules do not impose equiva-

lence between certification entities and these entities

(balancing and demand response entities), as this could

make these mechanisms more rigid and less efficient.

However, to ensure that the data necessary to calculate the effec-

tive capacity level and accurately verify capacity164 is collected effi-

ciently, the rules define the combinations that are possible between

certification entities and balancing and demand response entities,

applying a simple principle: all sites that are part of the same balan-

cing entity or demand response entity must either belong to the

same certification entity or belong to certification entities that are

affiliated with the same capacity portfolio manager.

The rules include a specific treatment demand response:

1. A demand response certification entity is strictly equivalent to

one or more entities (balancing entity or demand response entity).

2. A demand response certification entity can modify its consti-

tution (i.e. the sites it comprises).

This flexibility afforded to demand response in creating certifi-

cation entities (2) offsets the strict equivalence constraint (1).

It is justified by the fact that the composition of balancing enti-

ties and demand response entities changes very frequently, and

their contractual ties with extraction sites must be able to evolve

with them. For generation capacity, the flexibility afforded by the

absence of the strict equivalence requirement makes it possible

to address situations where relevant data for certain facilities

(hydro capacities for instance) are only available on a broader

scale than the certification entity (entire hydropower valley).

The method adopted for linking certification entities and balan-

cing/demand response entities (or the absence of linking)

affects the procedures used to collect and verify capacity data.

The way the activatable power of demand response capacity

is collected will typically differ depending on whether it parti-

cipates in the balancing mechanism. At the same time, capa-

city that does not participate in any of these mechanisms can

only be rewarded for the power activated, in keeping with the

mechanism objectives.

5.6.2 Collection of activated power data

The collection of activated power data is based:

> For generation capacities, on metering data for injections to

the public transmission and distribution systems;

> For demand response capacities, on the results of the load

reduction verification methods put into place on the NEBEF

and balancing mechanisms.

Records, in MW, of the participation of capacities in primary and

secondary system regulation are incorporated into the calcula-

tion of activated power.

164In filing a certification request, the capacity operator just indicate specific combinations for its capacity, which must be active during the verification. If a capacity does not comply with the configuration requirements, the data collected and verified shall be considered null.

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CAPACITY CERTIFICATION / 5

5.6.3 Collection of activatable power data

The collection of activatable power data is based on:

> Upward offers made on the balancing mechanism for capaci-

ties participating in it;

> A specific system incorporating the methods of rewarding

demand response on energy markets for demand response

capacity not participating in the balancing mechanism. This

system relies on declarations by demand-side operators,

notably containing:

• The sheddable load record that will be taken into

account as activatable power for the share not effectively

activated;

• The technical and economic conditions for activation,

particularly the price above which the capacity will be

activated;

• The demand response entities concerned.

The first declaration submitted through this system must be

received by 11am.

5.6.4 Collection of maximum energy data for PP2 days

The collection of maximum energy data for PP2 days is based

on existing systems, notably the balancing mechanism, but

additional information is required from operators

to account separately for the hours during which

shortfall risks are the greatest. Indeed, “maxE” decla-

rations made on the balancing mechanism may

cover a whole day, whereas the capacity mecha-

nism targets a specific time slot. Basically, capaci-

ties that are available and activatable outside these

hours do not contribute to reducing the shortfall

risk, and this must be reflected in their effective

capacity level.

5.6.5 Collection of weekly maximum energy data

New systems will have to be implemented to collect weekly

maximum energy data. The existing systems cover a one-day

window and weekly maximum energy does not correspond to

the sum of daily maximum energies of the days making up the

week165.

To this end, operators will have to submit new declarations on

their energy stocks. The type of information required is similar

to that provided with certification requests to justify declared

values (one example would be upstream reservoir levels repor-

ted for hydro capacity).

165The value of the daily maximum energy depends on the activations of previous days. Concretely, a capacity that can only be activated one day a week can declare, each day of the week, a daily maximum energy corresponding to a stock covering one day if it is never activated. If the weekly maximum energy was calculated as the sum of the daily maximum energies, it would then correspond to a possible activation for five days in a row.

5.7  Capacity verification 

The importance of verifications in a system relying on declara-

tions with controls after the fact was discussed at the beginning

of § 5.6. In drafting the rules, RTE focused on proposing control

procedures that (i) allow for an efficient verification of the effec-

tive availability of capacities and their contributions to reducing

the shortfall risk, (ii) are extensions of existing systems, as this

minimises costs, and (iii) create possibilities for new entrants

to effectively compete with existing capacities, notably in the

demand response sector, in keeping with the objectives outli-

ned in § 1.4.

The first criterion for evaluating verification procedures is their

efficiency in safeguarding security of supply and ensuring that

each capacity is rewarded in proportion to its contribution to

security of supply:

> Verifications must prevent the appearance of “phantom” capa-

cities (capacities that exist only on paper and cannot contribute

to security of supply): therefore, all capacities must have been

activated at least once by the end of the delivery period;

> It must also be possible to use verifications to establish whe-

ther operators have met their availability commitments: verifi-

cations of capacity must therefore be systematic.

The second criterion is that verification procedures must be

extensions of existing mechanisms for gathering data. This ties

in directly with the choices discussed in §  5.6, i.e. the priority

given to using the balancing and NEBEF mechanisms as the

main channels for gathering and checking data. Introducing

new verification mechanisms that are not extensions of existing

ones would inevitably drive up the costs associated with the

mechanism’s implementation.

Thirdly, verification procedures must not, generally speaking,

create entry barriers. In the particular case of demand response,

150

which public authorities have opted to promote as a structu-

ral response to the need to ensure long-term equilibrium in

the power system, barriers to aggregation must be abolished.

Any inconsistent or redundant verification measures applied

to demand response entities would be a step backward with

regard to the progress made in France since 2010. This is why

RTE is proposing that verification not be fragmented beyond the

certification entity level:

> If a capacity (certification entity in this context) is connected

to only one public system (for instance one PDS), verification

will be ensured by the corresponding system operator, as part

of the responsibilities entrusted to it in the decree;

> If a capacity (certification entity) comprises facilities or sites

connected to several public systems, verification will be ensu-

red by RTE, though the data relating to each capacity will be

conveyed through the relevant system operators.

The role assigned to distribution system operators in terms of

verification must be considered in the light of the Competition

Authority opinion of 20  December 2013, which, on the related

subject of the “demand response” decree provided for in the

Brottes Act of 15 April 2013, suggested that distribution system

operators should not take part in verifications of demand res-

ponse. The rules proposed by RTE comply with the decree of

December 2012, which specifically gives these operators an ope-

rational responsibility in verification, and take the Competition

Authority’s opinion into account whenever possible.

The sections below outline the verifications the rules provide for

in accordance with these principles, from the certification request

stage all the way through to the delivery period concerned.

5.7.1 Initial consistency check at the time of certification

When a capacity certification request is received, a series of

consistency checks is carried out to verify the information

declared by operators, notably focusing on:

> Compliance of the data used to identify existing capacities

(e.g. CARD or CART contract);

> Compliance of the estimated available power of the capacity,

which cannot be greater than (i) the sum of the Net Continuous

Power values of the production sites of a generation capacity or

(ii) the sum of the subscribed power values of extraction sites for

existing demand response capacities.

5.7.2 Verification of certified intermittent capacities under the normative approach

The verification procedure applied to operators that have opted

for the normative approach described in §  5.1.2.1.3 (neutrali-

sation of the risk affecting the primary source of intermittent

capacities) has been adapted. Verification is intended to ensure

that the capacities effectively contribute to security of supply

during the PP2 peak period. For instance, an intermittent capa-

city that undergoes extended maintenance during the delivery

year should not be issued certificates. With this adaptation, the

normative approach to availability is compatible with the stated

goal of not issuing certificates to capacities that do not effecti-

vely contribute to security of supply in a given year.

5.7.3 Verification of certified capacity under the generic approach

The procedure for verifying certified capacity under the generic

approach involves two separate levels of controls:

> Most capacities are regularly dispatched on the energy market or

balancing mechanism: in this case verification simply involves chec-

king that declared data matches up with collected data (availability);

> Some capacities are never dispatched on markets or the

balancing mechanism (unless a shortfall situation actually

occurs): they are verified by being regularly activated outside

the merit order to confirm that they are in working order;

> For capacities subject to specific technical or energy constraints,

additional verifications are required, either through desk or on-

site audits.

These verification procedures are based on generic processes

and can be applied with the same standards to generation and

demand response capacities.

5.7.3.1 Verification of injected quantities

These verification procedures involve analysing data relating to

the activation of capacities to calculate their effective availability.

Actual results are taken into account in order to verify a capacity’s maxi-

mum available power (factoring in the sensitivity of available power to

weather conditions) and its ability to be activated at the power level

required (success of upward offers for the balancing mechanism,

compliance of demand response programmes for NEBEF).

5.7.3.2 Activation tests

During the consultation, it became apparent that capacity

availability could not be confirmed solely on the basis of these

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CAPACITY CERTIFICATION / 5

verification procedures and that “physical” activations could be

required. Since verification methods evolve rapidly, RTE opted

to outline the guiding principles for activation tests rather than

setting precise procedures in stone.

Though no stakeholders opposed the idea of activation tests,

there was some discussion about who should bear the related

costs. The rules put into practical application the provision of the

decree calling for operators to be billed for the “costs incurred

by [the system operator to which the capacity is connected] for

the certification and verification of their capacity” (article 9). To

limit the extra costs to the community of too large a number of

tests, a capacity cannot be tested more than three times within

a given delivery year. The rules also stipulate that the tests must

be decided on and carried out by system operators in a propor-

tionate manner and under the supervision of CRE.

Activation tests may cover all of the technical parameters decla-

red by the operator; however, their main aim will be to verify the

activatable power of capacities. Any capacity that has a non-

zero activatable power (i.e. that is not fully activated) can be sub-

jected to one or more activation tests. The scope of activation

tests is limited and regulated: for instance, if an activation test

focuses on verifying activatable power and the capacity fails, the

consequences will relate only to the activatable power level on

record.

Two approaches to activation have been adopted:

> Within the market. The technical and economic data declared

for demand response capacity not participating in the balan-

cing mechanism must be verified through activation (if the

spot price is higher than the price indicated by the operator, a

NEBEF has to be declared, or else the capacity is considered to

fail the activation test within the market);

> Outside the market. Random tests are carried out without

prior notice to operators. At each time step of the PP2 period,

a random sample is taken for each activatable but non-acti-

vated capacity. A sample is taken for each capacity (not for

one out of all the non-activated capacities). There is therefore

no systematic activation on each time step. Activation pro-

babilities are determined in such a way that a capacity that

is not activated once within the market over the entire PP2

period has a high probability of being activated through tests.

Conversely, a capacity that is activated over a significant part

of the PP2 period has a very low probability of being activated

during the time steps when it is not in use. A capacity’s proba-

bility of being activated also incorporates the results of audits

where applicable.

At the end of the delivery period, all capacities will have been

activated at least once through the verification system (activa-

tion test) or another system.

There is also a question about responsibility for verifications,

particularly after the Competition Authority’s recent opinion on

demand response. Under the rules, tests conducted on an entity

comprising sites connected to only one system will be decided

by the operator of that system and carried out by RTE through

the balancing mechanism, thus providing an aggregated view

of all capacities. Where demand response is concerned, these

provisions might not comply with the recommendations in the

opinion issued by the Competition Authority on 20 December

2013: RTE would like to point out that total compliance with

this recently issued opinion would require an amendment

of the decree of 14  December 2012 instituting the capacity

mechanism.

5.7.3.3 Audits

Verifying some technical parameters or energy constraints

declared for capacities necessarily require audits.

The rules distinguish between and describe two types of audit:

> Desk audits: according to the rules, an operator must provide

to RTE, through a distribution system operator if its capacity is

only connected to that operator’s network, all information that

can be used to validate the technical parameters declared for

its capacity. For instance, an audit of the data declared with

the certification request about weekly maxE may be ordered,

and the operator will then have to submit data that can be

objectively validated (measurements, updated file, etc.);

> On-site audits: once a certification contract has been signed,

RTE, a third party mandated by it or a distribution system ope-

rator (if all capacities within a certification entity are connec-

ted to its network) can at any time go to a capacity site or any

other site where it is possible to measure, monitor and acti-

vate capacities, and can ask the operator to produce any proof

of the technical characteristics declared and its ability to start

and monitor activations.

The comments above about the role of system operators in

verifying capacities also apply to audits, the Competition Autho-

rity having considered in its opinion of 20 December 2013 that

distribution system operators should not take part in the verifi-

cation of demand response. The rules proposed by RTE comply

with the decree of December 2012 on the capacity obligation.

152

The capacity mechanism is designed to function in a works

within a decentralised market architecture; this structure deci-

sion is in keeping with the founding principles of the internal

European energy market166 and particularly the core principle

of holding market stakeholders accountable. Under this struc-

ture, suppliers and capacity operators are active with regard to

their obligations and commitments, and have incentives to take

the actions required to help maintain security of supply strictly

within their respective perimeters.

This principle of accountability applies when it comes to fore-

casting demand or generation plant availability needs167, and

also to the capacity mechanism rules regarding settlements,

as provided for in the decree. Similarly to the imbalance settle-

ment system in place in the energy sector (the imbalance set-

tlement price must reflect the cost of the imbalances observed

within the perimeter of a balance responsible party), the rebal-

ancing price for suppliers and the imbalance settlement for

capacity portfolio managers hold stakeholders responsible for

the cost associated with their imbalances. The market mecha-

nism implemented thus encourages suppliers to cover their

obligations as accurately as possible and incentivises capacity

operators to submit their best power availability estimates for

their facilities.

The provisions relating to governing settlements in the capacity

mechanism rules will thus play a central role in incentivising mar-

ket stakeholders to adopt behaviours and make economic deci-

sions that help meet the security of supply target. For the capacity

mechanism to function efficiently, market stakeholders must: (i)

have incentives to base their actions on their best forecasts, (ii)

not be able to make arbitrages that are suboptimal collectively,

and (iii) have incentives to disclose information and transfer it to

the market so it can be efficiently integrated into the price.

The present This chapter presents the provisions in the capacity

mechanism rules that relate to how these incentives translate

into settlements. It begins with an overview of the general prin-

ciples applicable to the settlement for capacity rebalancing by

suppliers and the imbalance settlement for capacity portfolio

managers (§ 6.1). The factors to be taken into account in the

capacity mechanism rules for the calculation of settlements are

then discussed (§ 6.2). A third section reviews the options rela-

tive to settlements included in RTE's proposal (§ 6.3).

6.1 General principles of settlements

Article 1 of the decree describes the settlement relating to rebal-

ancing by suppliers and that relating to imbalances of capacity

portfolio managers.

The settlement for supplier rebalancing is the financial trans-

action conducted between that supplier and the transmis-

sion system operator when rebalancing occurs for a given

delivery year.

The capacity portfolio manager imbalance settle-

ment is the financial transaction conducted by that

manager when the total effective capacity within

its portfolio differs from the total capacity certi-

fied, or when a capacity operator in its portfolio

rebalances.

6. THE CAPACITY MECHANISM SETTLEMENT SYSTEM

166See chapter 2 of this report.

167See chapters 4 and 5 of this report.

168See chapter 3 of this report.

The sections below discuss the provisions in the decree that

relate to these definitions and within the framework of which

RTE has made its proposal related to settlements.

6.1.1 Capacity rebalancing by suppliers

The provisions concerning relating to the settlement for capacity

rebalancing by suppliers are found in article 6 of the decree. An integral

part of the model chosen by public authorities, these provisions were

introduced while the decree was being prepared, after being approved

by the Energy Regulatory Commission168, to ensure that efficient eco-

nomic incentives are in place to make suppliers accountable.

A settlement for capacity rebalancing by a supplier is proportion-

ate to the supplier's imbalance – i.e. the difference between the

153

THE CAPACITY MECHANISM SETTLEMENT SYSTEM / 6

amount of its capacity obligation and the amount of capacity

certificates held in its account – and to a unit price that depends

on the sign of the imbalance.

The decree also stipulates that the method of calculating the

unit price for capacity rebalancing must be defined in such a

way as to (i) ensure, over the medium term, that suppliers have

an economic incentive to meet their capacity obligation, (ii)

encourage suppliers to evaluate their capacity certificate needs,

with an eye to meeting their capacity obligation, based on a

good faith estimate of their customers' reference power, and

to (iii) limit arbitrage possibilities between an imbalance settle-

ment at the capacity portfolio manager level and a settlement

for rebalancing at the supplier level.

This calculation method is approved by the Energy Regulatory

Commission, on the basis of a proposal by the public electricity

transmission system operator.

6.1.2 Imbalance settlement at the capacity portfolio manager level

The provisions relating to concerning the settlement for imbal-

ances at the capacity portfolio manager level are found in article

14 of the decree.

Under the terms of the decree, the imbalance settlement

of a capacity portfolio manager is calculated based on the

capacity portfolio manager's imbalance  – i.e. the difference

between total effective capacity and total certified capacity

within its portfolio – and the sum of the amounts rebalanced

within its capacity portfolio. If rebalancing has occurred several

times, the settlement also takes into account the number and

direction of these adjustments. Thus, for a given imbalance,

recourse to rebalancing will increase the algebraic value of the

settlement compared with a situation where rebalancing did

not occur.

The decree also stipulates that the method of calculating the

imbalance settlement of a capacity portfolio manager must be

determined in such a way as to (i) ensure, over the medium term,

that operators have an economic incentive to meet their com-

mitments, (ii) encourage capacity operators to submit truthful

information with certification and rebalancing requests, particu-

larly regarding the projected availability of their capacity, and

to (iii) limit arbitrage possibilities between an imbalance settle-

ment at the capacity portfolio manager level and a settlement

for rebalancing at the supplier level.

6.1.3 Overview of principles governing settlements

The formula applied in calculating the settlement can be written

as follows:

Capacity rebalancing by suppliers

Settlement = – imbalance

Volume x unit

Price

A supplier with a negative imbalance pays the amount corre-

sponding to its imbalance, multiplied by the settlement price

for negative imbalances, into the settlement fund for capacity

rebalancing by suppliers.

A supplier with a positive imbalance receives the amount cor-

responding to its imbalance, multiplied by the settlement price

for positive imbalances, from the settlement fund for capacity

rebalancing by suppliers. It may receive less if the balance in the

account is too low to compensate all stakeholders with positive

imbalances. In this case, they will receive a settlement propor-

tionate to their imbalance.

Imbalance settlement for capacity portfolio manager

Settlement = – imbalance

Volume x unit

Price + rebalancing

Cost

Capacity portfolio managers with negative imbalances pay into

the settlement fund for capacity portfolio manager imbalances

the amount corresponding to their imbalances, multiplied by

the negative imbalance settlement price, plus the cost associ-

ated with rebalancing.

Capacity portfolio managers with positive imbalances receive

from the settlement fund for capacity portfolio manager imbal-

ances the amount corresponding to their imbalances, multiplied

by the positive imbalance settlement price, plus the cost associ-

ated with rebalancing. They may receive less if the balance in the

account is too low to compensate all stakeholders with positive

imbalances. In this case, they will receive settlements proportion-

ate to their imbalances.

154

6.3 Settlements provided for in the rules

To ensure that the settlement gives stakeholders the right eco-

nomic incentives, RTE drafted the capacity mechanism rules

with three key parameters in mind, the goal being to ensure that

the settlement will give stakeholders the right economic incen-

tives: the security of supply criterion set by public authorities

(§ 6.2.1), the reference unit price of the settlement used to cal-

culate the imbalance price (§ 6.2.2) and the interplay between

capacity rebalancing by suppliers and the imbalance settlement

for capacity portfolio managers (§ 6.2.3).

6.2.1 Security of supply target

The decree stipulates that the settlement system can be

adapted when “there is no significant threat to security of sup-

ply”. Moreover, article L.335-2 of the Energy Code states that

“obligations assigned to suppliers are calculated in such a way

as to incentivise them to work, over the medium term, towards

the security of electricity supply target used to prepare the Ade-

quacy Forecast Report”.

These provisions show that In other words, the calculation of the

settlement system must support the objective of safeguarding

security of supply and be proportionate to this objective. The

settlement definition adopted in the capacity mechanism rules

must therefore take into account both the security of supply cri-

terion and the imbalance amount (in absolute terms) beyond

which the threat to security of supply is considered significant.

6.2.2 Unit price of the settlement

The provisions of the decree explicitly state that a settlement amount,

be it for an imbalance at the capacity portfolio manager level or for

capacity rebalancing by a supplier, is based on a unit price.

6.2 Key aspects of capacity mechanism settlements

6.2.3 Interplay between capacity rebalancing by suppliers and imbalance settlement at the capacity portfolio manager level

The efficiency of the provisions governing the settlement can-

not be measured solely by analysing the impact of each compo-

nent separately: a broad assessment of stakeholders' economic

results is required. The settlement creates incentives through

the gains to which stakeholders can aspire and the risks to

which they are exposed.

Market stakeholders' economic results may overlap with incen-

tives for capacity rebalancing by suppliers and the imbalance

settlement at the capacity portfolio manager level for integrated

companies.

The challenge in drafting the rules was to manage the interplay

between the systems applicable to capacity rebalancing by sup-

pliers and imbalance settlements for capacity portfolio manag-

ers while upholding the provisions of the decree that seek to

limit the possibility for stakeholders to arbitrage between the

two types of settlement.

6.3.1 Interplay between capacity rebalancing by suppliers and the imbalance settlement at the capacity portfolio manager level

To ensure that the settlement creates the right incentives, and

that integrated stakeholders cannot engage in arbitrage, the

systems governing rebalancing by suppliers and the imbalance

settlement for capacity portfolio managers must be aligned.

Indeed, an imbalance between the number of capacity certifi-

cates held by an integrated stakeholder and its obligation could

alternatively be considered a certification or obligation compo-

nent, depending on the number of certificates transferred by

the part of the company that acts as an “operator” to its “sup-

plier” arm.

The challenge in drafting the rules was to deter-mine the reference or references to be that should be used to calculate this unit price. Two options emerged during the consultation:

> A unit price based on prices applied in different mechanism-related transactions (market price);

> A unit price set at the administrative level.

155

THE CAPACITY MECHANISM SETTLEMENT SYSTEM / 6

∆V

Capacitylevel

Obligationlevel

Capacitycertified

level

Imbalancesettlement

at CPM level

Player certifiesat obligation level

Pays ΔV * CPM settlement price

Capacitycertified

level

Imbalancesettlementat supplier

level

Real situation Player certifies at capacity level

Pays ΔV * Supplier settlement price

Figure 72 – Interplay between obligation- and certification-related settlements

The chart below illustrates how an integrated stakeholder could

arbitrage between its imbalance as a supplier and its imbalance

as a capacity portfolio manager when it shows an imbalance

(ΔV) between its obligation and capacity.

If the stakeholder opts for the capacity portfolio manager set-

tlement, its imbalance ΔV will be valued based on the capacity

portfolio manager settlement price. In the other case, the set-

tlement will be equal to the product of ΔV and the supplier set-

tlement price. To make arbitrages impossible, the capacity port-

folio manager settlement price and supplier settlement price

must be equal.

Having a “supplier” settlement and a “capacity portfolio man-

ager” settlement comes down to defining a settlement unit

price that represents the same variable for capacity rebalancing

by suppliers and the imbalance settlement for capacity portfolio

managers. This approach is also in keeping with the idea that

all contributions to the shortfall risk should be treated equally,

whether generated by an imbalance at the level of a supplier

or capacity portfolio manager.

Arbitrages between an imbalance settlement at the capacity portfolio manager and supplier levels are effectively prevented when the unit price for rebalancing by suppliers is the same as the unit price for rebalancing by capacity portfolio managers.

6.3.2 Unit price for the settlement and the security of supply target

The decree specifies that the unit price for the settlement can

be adapted when there is no significant threat to security of sup-

ply. Bearing this in mind, RTE is proposing a two-part settlement

scheme:

> When security of supply is not at risk, the settlement price will

be based exclusively on the market price. In this case, stake-

holders are not penalised for imbalances, which are simply

restated based on their market value. An incentive coefficient

K is nonetheless still necessary to incentivise stakeholders to

go through the market rather than wait for a settlement;

> When security of supply is at risk, the settlement price must

switch over to an administered price. This price, which by

definition sets the maximum value capacity can reach on the

market, plays a key role in creating incentives to invest in new

capacitiesy. It is therefore set based on the annualised cost of

the reference peak-load capacity and made public four years

before the delivery year.

By structuring the settlement around the market price in this

way, the mechanism introduces an important self-regulation

function that makes the signals generated by the capacity mar-

ket more consistent with forecast levels of security of supply lev-

els. This ensures that if overcapacity becomes an issue, the ref-

erence market price can be low or even zero, reflecting the state

of the system, and thus avoid unnecessary extra costs for con-

sumers. Conversely, if capacity is tight in terms of safeguarding

156

security of supply, the reference market price will rise, in line with

anticipated tension in the system.

Settlements are thus shaped by two reference prices: a refer-

ence market price (MarP) and an administered price (AdminP).

RTE proposes that the “reference capacity price for the deliv-

ery year” and the “maximum price determined with reference

to the cost of building new capacity”, defined by CRE169, be

used as the reference market price and the administered price,

respectively, for settlements within the framework of the capac-

ity mechanism.

6.3.3 Definition of indicators for assessing threats to security of supply

With a settlement scheme based on the actual level of secu-

rity of supply, a meaningful indicator must be determined

to estimate if security of supply is effectively threatened

(§ 6.3.3.1) and a threshold value must be defined for this indi-

cator (§ 6.3.3.2).

6.3.3.1 Determining the overall imbalance

The decree stipulates that the settlement scheme can be calcu-

lated based on “the sum of the imbalances of capacity portfolio

managers and the difference between the sum of the capacity

obligations of suppliers and the total capacity certificates they

hold as of the capacity certificate transfer date”. In other words,

the decree stipulates that the difference between effective

capacity levels and the aggregated obligations of all obligated

parties in France (assuming that all certificates effectively par-

ticipate in the market) is the indicator to be used to determine

whether security of supply is at risk. This difference corresponds

to the overall imbalance.

This choice of the Using the overall imbalance

observed as the indicator for measuring the threat

169Decree 2012-1405, Article 23

Table 4 – Matrix of the imbalance settlement depending on the state of the system

Security of supply at risk Security of supply not at risk

Negative imbalance settlement price AdminP (1+K) MarP

Positive imbalance settlement price (1-K) MarP (1-K) MarP

to security of supply creates incentives that are consistent with

the actual state of the system and enhances the mechanism's

efficiency. The signal generated by the market closely reflects

physical tension between effective obligations levels and effec-

tive capacity levels. Any risks that emerge on either side are

communicated to the market and can be addressed with capac-

ity adjustment measures. In particular, demand response and

load reduction capacity, suitable responses to short-term capac-

ity concerns, can be fully leveraged.

Using the overall imbalance observed as the indicator also pre-

vents stakeholders from manipulating the market by certifying

an excessively high (or low) level of capacity to artificially modify

the market price.

In such situations, if the imbalance price was based on the fore-

cast overall imbalance, measures with an activation cost that is

higher than the imbalance price based on the reference market

price will not be activated, even though the state of the system

would justify their use.

The actual level of security of supply would be lower, as

would the rewards offered for such measures, particularly on

the demand side, than if the actual imbalance was taken into

account.

Conversely, the actual state of the system might not be as

unfavourable as anticipated. In this case, capacity could be

dispatched even when the level of security of supply did does

not require it, thus generating extra costs for suppliers and, ulti-

mately, for consumers.

6.3.3.2 Determining the maximum imbalance

If the overall imbalance observed is considered the best indica-

tor to assess the threat to security of supply, then a threshold

value must be defined to establish the level beyond which the

157

THE CAPACITY MECHANISM SETTLEMENT SYSTEM / 6

overall imbalance observed is considered to pose a threat to

security of supply. This threshold value is referred to as the maxi-

mum imbalance.

Above and beyond the objective of keeping the settlement

proportionate, the challenge for RTE in determining the maxi-

mum imbalance is to ensure that market stakeholders have

sufficient visibility on the settlement scheme to which they

will be subject.

The sensitivity analyses conducted on the obligation, presented

in chapters 4 and 5 of this report, provide preliminary informa-

tion about the variability of the capacity mechanism, applying

the provisions of the capacity mechanism rules to the six years

between 2006 and 2011.

Figure 73 – Illustration of the impact taking the actual imbalance in the system into account has on measures activated during the delivery year

Figure 74 – Imbalance settlement scheme applicable depending on the overall imbalance observed

Overall imbalance0 Maximum imbalance

Security of supply not at risk

Reference market price

Security of supply at risk

Administered price

Overall imbalance

Negative imbalance price

oI est.

oI (overall imbalance) actual

oI actual

Price gap not factored in,preventing activationof resources, notablyon demand side

AdmP

MarP

oIlimit

Overall imbalance

Negative imbalance price

oI est.

OI (overall imbalance) with resources activated

Imbalance price withoutresources activated

Imbalance price withresources activated

1

2

RTE proposes that the maximum imbalance be defined in such a way as to ensure that the set-tlement scheme does not depend on the occur-rence of short-term risks, and that the maximum imbalance be published before the start of the delivery year.

The maximum imbalance could be set factor-ing in a quantity of uncontrollable risks – i.e. the amount of risks that stakeholders would not have sufficient resources to cover.

Setting the maximum imbalance at 2 GW ensures that a switch from the market price to the admin-istered price will occur only when there is a sig-nificant threat to security of supply, without depending on the materialisation of short-term risks.

158

6.4 Assessment of the impact of the provisions on settlements for market stakeholders

6.4.1 Framework for the assessment

The previous sections outlined the defining choices made in the

rules to ensure that the settlement scheme incentivises stake-

holders to balance through the market rather than wait for a

settlement. With the way settlements are calculated, the settle-

ment price for rebalancing by suppliers or imbalance settlement

by capacity portfolio managers is lower than the market price

when they show positive imbalances and higher when they

show negative imbalances. Relying on the settlement thus has

a cost for stakeholders.

Moreover, if security of supply is at risk (i.e. if the overall imbal-

ance observed exceeds the value of the maximum imbalance

set by RTE before the start of the delivery year), a settlement

for supplier rebalancing or an imbalance at the capacity portfo-

lio manager level will be based on the administered price. The

switchover to the administered price entails additional costs for

stakeholders showing imbalances.

Lastly, articles 7 and 14 of the decree stipulate that the settle-

ment fund for capacity rebalancing by suppliers and the settle-

ment fund for capacity portfolio manager imbalances cannot

have a negative balance170 and that settlements paid out from

them is reduced proportionately to ensure that the sum of the

settlements paid is equal to the amount available in the account.

This provision creates an additional incentive for stakeholders

with positive imbalances to rebalance through the market, but

can generate additional costs (particularly for stakeholders with

a zero imbalance expectation and thus only showing a small

imbalance).

The financial risk to which market stakeholders are

exposed – , suppliers through the rebalancing set-

tlement and capacity portfolio managers through

the imbalance settlement,  – can be analysed. Inso-

far as stakeholders can turn to the market if risks

materialise before the start of the deliver year, sup-

pliers by buying or selling certificates and capac-

ity portfolio managers by rebalancing one or more

times, the study focuses only on the residual risks

that can impact stakeholders during the delivery

year, i.e. the real-time risks that cannot be offset

through the market.

6.4.2 Principle of the study

The model comprises ten market stakeholders each with a sup-

plier perimeter and a capacity portfolio manager. We begin at

the start of the delivery year, in the following situation:

> The reference market price has been set;

> Each stakeholder positions itself based on its best estimate

(anticipated value).

We then model the residual uncertainty stakeholders face

with regard to availability and obligation levels, with a variable

centred on 0. The variables are independent standard normal

distributions. Each simulation represents a delivery year for

the mechanism, and yields the settlement to which each par-

ticipant is subject. The same climate scenario is used on the

obligation and certification sides. The simulation is repeated

a large number of times to obtain the average settlement per

participant.

Structure of the settlement

The structure of the settlement modelled is the one proposed

by RTE in the draft capacity mechanism rules. The parameters

were defined as follows:

Parameter Value applied

Administered price (€k/MW) 60

Maximum imbalance (GW) -2

K 0.1

Two assumptions are used for the reference market price: €10k/

MW and €30k/MW (see chapter 8 as well).

Risks incurred by stakeholders

The risks incurred by stakeholders are defined by a standard

deviation based on their size. Two distributions of risks between

stakeholders are simulated: in the first case, standard deviations

for risks are proportionate to stakeholders' capacity/obligation

levels, and in the second the standard deviations are lowered to

factor in risk -spreading.

170Article 7 of the decree: The sum of the amounts paid out of the fund cannot exceed the sum of the amounts effectively paid in by suppliers with positive settlement for that delivery year.Article 14 of the decree: The sum of these settlements cannot exceed, for a given delivery year, the sum of amounts effectively paid in for positive settlement.

159

THE CAPACITY MECHANISM SETTLEMENT SYSTEM / 6

Case 1: Risks proportionate to stakeholders' capacity or obligation

Risks are aligned as follows:

> For the supplier share: the standard deviation represents 1.5% of the obligation;

> For the capacity portfolio manager share: the standard deviation represents 2% of certified capacity.

The resulting breakdown between stakeholders is as follows:

171Obligation – Capacity level

Stake-holder 1

Stake-holder 2

Stake-holder 3

Stake-holder 4

Stake-holder 5

Stake-holder 6

Stake-holder 7

Stake-holder 8

Stake-holder 9

Stake-holder 10 TOTAL

Capacity level/Obligation (GW) 60 15 10 5 3 2 2 1 1 1 100

Standard deviation for obligation risk (GW) 0.90 0.23 0.15 0.08 0.05 0.03 0.03 0.02 0.02 0.02 0.95

Standard deviation for capacity risk (GW) 1.2 0.3 0.2 0.1 0.06 0.04 0.04 0.02 0.02 0.02 1.25

The total variability for the system171 is close to 1.6 GW, consistent with the results obtained using historical data, which showed a maxi-

mum overall variability of 1.6 GW.

Case 2: Risks taking into account risk spreading

The alignment of risks per stakeholder is shown in the table below, taking into account whether stakeholders they have the ability to

smooth their imbalances. Risk spreading reduces the standard deviations for the three largest stakeholders:

Stake-holder 1

Stake-holder 2

Stake-holder 3

Stake-holder 4

Stake-holder 5

Stake-holder 6

Stake-holder 7

Stake-holder 8

Stake-holder 9

Stake-holder 10 TOTAL

Capacity level/Obligation (GW) 60 15 10 5 3 2 2 1 1 1 100

Standard deviation for obligation risk (GW) 0.68 0.21 0.14 0.08 0.05 0.03 0.03 0.02 0.02 0.02 0.73

Standard deviation for capacity risk (GW) 0.90 0.29 0.19 0.10 0.06 0.04 0.04 0.02 0.02 0.02 0.97

6.4.3 Results

The first observation is that the average settlement cost in

relation to stakeholders’ capacity or obligation levels is small.

For a stakeholder with an obligation of 10 GW, the amount is

€0.27k/MW, broken down as follows:

Average settlement cost

Negative imbalance settlement (€k/MW) 0.51

Positive imbalance settlement (€k/MW)

-0.23

Total (€k/MW) 0.27

Average settlement cost for stakeholder 3

(Reference market price = €30k/MW)

Average settlement cost

Negative imbalance settlement (€k/MW) 0.25

Positive imbalance settlement (€k/MW) -0.07

Total (€k/MW) 0.18

Average settlement cost for stakeholder 3

(Reference market price = €10k/MW)

The simulation results are presented in the chart below. The red

curve represents the results obtained for stakeholders' imbal-

ance settlement costs in the simulation with risks distributed

proportionately to their capacity or obligation levels. The green

curve shows the results obtained for stakeholders' imbalance

160

settlement costs in the simulation that takes into account their

ability to smooth their imbalances.

With risks distributed in portion to stakeholders' capacity or obli-

gation levels, the settlement cost is proportionately higher as

the stakeholder’s' size increases. For a stakeholder with 60 GW

of capacity, the settlement cost is €0.48k/MW, compared with

€0.24k/MW for one with 1  GW (assuming a reference market

price of €30k/MW).

This result depends on the stakeholder's quantity of risks in rela-

tion to the overall imbalance defi ned as the maximum imbal-

ance. A larger stakeholder (with potentially high risks) can by

itself, if it has a negative imbalance, trigger a shift in the overall

imbalance on the system and thus a switch to the administered

price. A larger stakeholder will therefore settle negative imbal-

ances at the administered price more often than a smaller one,

given the correlation between the imbalance settlement regime

determined and the sign of its imbalance.

Taking into account the ability to spread risks reduces the imbal-

ance settlement cost for larger stakeholders, from €0.48k/MW to

€0.28k/MW172. It can also be observed that all stake-

holders benefi t from the spreading of risks through a

lower average imbalance settlement cost, including

smaller stakeholders for which risk levels have not

changed. This is explained by the decline in the overall

variability of the system173 from 1.6 to 1.2 GW.

0

10

20

30

40

50

60

70

80

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

GW

€k/M

W

Player 1

Player 2

Player 3

Player 4

Player 5

Player 6

Player 7

Player 8

Player 9

Player 10

Figure 75 – Settlement cost based on size of stakeholder (reference market price assumed = €30k/MW)

      Total capacity

Imbalance settlement cost, 1st case

Imbalance settlement cost with smoothing

The impact assessment conducted on the provi-sions relating to settlements in the draft capacity mechanism rules produced three key results:

> A larger stakeholder will face a higher set-tlement cost than smaller stakeholders as a whole. Due to its size and the potential signifi -cance of its risks, there is indeed a correlation between its imbalance and the overall imbal-ance on the system: all other things being equal, a larger stakeholder will therefore settle negative imbalances at the administered price more often;

> A stakeholder facing fewer a smaller quantity of risks does not have to contend with the same issue and its settlement cost will thus be lower;

> All stakeholders benefi t from the spreading of risks, including smaller ones that cannot spread risks at their individual level; this is because the decrease in the system's overall variability results in a lower settlement cost for all stakeholders.

172Assuming a reference market price of €30k/MW.

173Obligation – Capacity level.

161

THE CAPACITY MECHANISM SETTLEMENT SYSTEM / 6

162

7. MARKET FUNCTIONING: TRADING, TRANSPARENCY AND COMPETITION The French capacity mechanism is based on suppliers being

required to have capacity coverage equivalent to the consump-

tion of their customers. This obligation allows all energy market

stakeholders to contribute to security of supply in proportion to

their contribution to the shortfall risk, and creates incentives to

keep peak demand growth in check, this being a key criterion for

evaluating the shortfall risk in France.

It would not be economically efficient to require that all obli-

gated parties ensure the physical coverage of their own obli-

gation if other operators can do it for them at a lower cost.

This is why obligated parties have the option to go through

the market and meet their obligation indirectly by buying from

a third party securities representing an operator’s unit contri-

bution to reducing the shortfall risk. These securities, called

capacity guarantees in the rules and capacity certificates in

this report, must therefore be carefully defined and they must

be negotiable.

This kind of market mechanism, designed to deliver a collec-

tive result, is in keeping with an existing body of theory deve-

loped in the economic literature based on the work of Ronald

Coase174. Creating standardised products called capacity certi-

ficates is a matter of creating property rights to reductions in

the risk of shortfalls on the power system and allowing market

stakeholders to trade them to meet the objective set by public

authorities at the lowest cost. A capacity market is thus crea-

ted through the trading of capacity certificates between market

stakeholders.

For such a system to be economically efficient, the property rights

need to be sufficiently well defined and related transaction costs

low enough, especially with regard to the gains stemming from

the optimisation of the provision of the good.

The first condition is considered to have been met if the number

of capacity certificates allocated to each resource through the

capacity certification process accurately reflects its contribution

to security of supply, and if those that buy capacity certificates on

the market are not held responsible for a potential failure of the

capacity to which the certificates were originally allocated. This

objective is met through the certification principles outlined in

chapter 5 of this report and the method of calculating whether an

obligated party has met its obligation found in chapter 4.

The second condition can only be met in relative terms, insofar

as there will necessarily be transaction costs involved in creating

a new negotiable good from scratch. For transaction costs to be

considered sufficiently low to be economically optimal for the

capacity mechanism, specific conditions must be met:

1. It must be possible for stakeholders to trade capacity certifi-

cates freely, based on their needs, and at prices that effectively

correspond to underlying costs;

2. Stakeholders must have access to relevant information to

understand the market fundamentals and act accordingly;

3. Competition in the market must be free and undistorted.

Some consultation participants voiced reservations about the third

condition, and to a lesser degree the second, as did the Competition

Authority175. Concerns about whether a market mechanism can

efficiently reveal the value of security of supply and ensure optimal

coordination of stakeholders’ decisions are legitimate, as these issues

are what will determine the mechanism’s economic efficiency. This

chapter outlines the measures intended to address them, notably

particularly those proposed in the capacity mechanism rules. The

provisions that would govern capacity certificate trading are pres-

ented in § 7.1, those relating to the transparency of the market and its

fundamentals in § 7.2, and those designed to ensure free and undis-

torted competition in the capacity market in § 7.3.

174[Coase, 1960]

175[Competition Authority, 2012a]

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MARKET FUNCTIONING: TRADING, TRANSPARENCY AND COMPETITION / 7

7.1  Trading of capacity certificates

For the capacity market to be efficient, transactions must

involve goods that are clearly defined, and the framework must

give stakeholders confidence in a system that allows them to

meet their obligation through the market rather than holding

physical capacity. Transactions should generate a signal-price

that reflects the state of the power system.

This “market-driven” approach requires that the mechanism’s

parameters be stable throughout each term. Otherwise, regu-

latory uncertainty could discourage stakeholders from trading,

especially several years before the delivery year, since the value

of a capacity certificate could change due to the intervention

of forces outside the market during a term. For instance, a

decrease in the security factor during a mechanism term would

reduce the value of a capacity certificate. The publication of the

mechanism parameters at the start of the term, i.e. four years

before the delivery year, provides the regulatory stability indis-

pensable to the smooth flow of trading. By reducing uncertainty

relating to the mechanism’s time horizons, it plays an important

role in shaping stakeholders’ forecasts.

The capacity mechanism rules are the foundation for capacity

certificate trading. They include all of the building blocks required,

from precise definitions (nature of the product, eligible stakehol-

ders, transfer system, etc.) to the tools to be implemented (crea-

tion of the register, traceability, etc.). Though the mechanism rules

do not institute an organised market for certificate trading, they

do lay the groundwork for its future creation by leaving enough

leeway for an exchange platform to be created.

The section below discusses the effects of the publication of the

parameters before the delivery year and the provisions intended

to make exchanges more fluid.

7.1.1 Publication of mechanism parameters at the start of the term

The publication of the definitive parameters at the start of the

capacity mechanism term gives suppliers sufficient visibility

to integrate their obligation into their customer contracts, to

cover their certificate needs ahead of time, to organise any

demand management actions necessary and, ultimately, to

meet their obligation. Operators can also anticipate their own

certified capacity level and thus the amount of certificates

that will be allocated to their capacities. This is especially

important when it comes to planned capacity and investment

decisions.

However, the fact that the mechanism parameters are defined

several years ahead of time and do not change after they are

published could create some uncertainty when they are being

set. It is impossible to reassess them later if the fundamentals

of security of supply change significantly and unexpectedly, and

this could make them less representative of security of supply.

This is another illustration of the compromise that must be

found between the accuracy and stability of the mechanism

(see section 3.2). The disadvantages in terms of accuracy are

nonetheless lessened by the fact that the mechanism does

not set a capacity target: as such, even if the mechanism para-

meters are not perfect, market stakeholders will reassess their

capacity needs and this will bring the value back into line with

the fundamentals.

A stable regulatory framework is thus crucial for trading to func-

tion smoothly, and its drawbacks in terms of when the parame-

ters are defined are offset by the absence of a fixed capacity

target. In this case, the benefits of stability far outweigh the

disadvantages in terms of accuracy.

The rules stipulate that all capacity mechanism parameters are

to be published together at the start of the term, i.e. four years

before the start of the delivery year:

> For the obligation: extreme temperature value and security factor;

> For certification: charts used for capacity certification, contri-

bution coefficients for each technology subject to the certifi-

cation approach that neutralises the risk affecting the primary

source of intermittent capacities;

> For settlements: the administered price representing the price

applied to negative imbalances when security of supply is

seriously threatened.

7.1.2 Nature of the product and organisation of trading

7.1.2.1 Nature of the “capacity certificate” product

Decree 2012-1405 of 14 December 2012 provides a definition

of the “capacity certificate” product:

A capacity certificate is intangible personal property, fungible,

negotiable and transferable, corresponding to a normative

164

unit power value, created by the public transmission system

operator and issued to a capacity operator after a capacity

has been certified and valid for a given delivery year.

Capacity certificates are all recorded in the capacity certificate

register kept by RTE. This register lists, in a secure and confiden-

tial manner, all transactions involving the issuance, exchange

or destruction of capacity certificates. The capacity certificate

register is opened once the first capacity certificates are issued.

Ownership of a capacity certificate is established once it is

recorded by RTE in the holder’s account in the capacity certi-

ficate register. Because capacity certificates are paperless, their

recording in the capacity certificate register constitutes suffi-

cient proof of ownership. The negotiable product exists separa-

tely once it is issued: a that holds a certificate bears no risk with

regard to the underlying capacity to which the certificate was

originally issued.

Each capacity certificate is valid only for a given delivery year.

This means that a capacity certificate issued for a delivery year

and recorded in an account in the register for that year cannot be

transferred to an account in a register for a different delivery year.

Capacity certificates are issued in units of 0.1  MW. They are

numbered to facilitate their management and the tracking of

exchanges.

7.1.2.2 Holder of an account in the capacity certificate

register

An account holder is a legal entity with at least one account in

the register. It may be an obligated party, a capacity portfolio

manager, an operator or any other participant in the market.

An account holder may have several accounts, depending on its

own capacity mechanism-related needs. However, an account

holder can only have one account as an obligated party. It is the

number of certificates held in this account that will be used to

calculate the supplier’s imbalance for capacity rebalancing, and

then to calculate its final imbalance.

7.1.2.3 Issuance and cancellation of capacity

certificates

As the body that maintains the register, RTE alone can issue or

cancel capacity certificates.

Certificates are issued when a capacity contract comes into

effect for a capacity that was not previously the subject of a

certification contract for the same delivery year, or in the event

of upward rebalancing by an operator. When certificates are

issued, RTE places an amount of certificates corresponding to

the amount certified in the contract in the holder’s account in

the capacity certificate register.

Capacity certificates can only be cancelled in the event of

downward rebalancing by an operator. RTE cancels the certifi-

cates once they have been returned to it by capacity portfolio

manager that rebalanced.

7.1.2.4 Transfers of capacity certificates

A capacity certificate changes ownership when it is transferred

between two legal entities each holding an account in the capa-

city certificate register.

To avoid factoring transactions conducted at prices that have

no economic relevance for the market as a whole into the refe-

rence price, the rules distinguish between two types of capacity

certificate transfers:

> Certificate transactions: certificates are transferred based on a

price agreed upon between the parties;

> Certificate transfers: the exchange is agreed upon between

the parties but with no payment involved.

All transaction prices must be notified to CRE in keeping with

paragraph I of article 17 of the decree.

7.1.3 Trading procedures

Capacity certificates can be traded bilaterally or through orga-

nised markets. A platform to concentrate liquidity would offer

real advantages in terms of forming and revealing a public refe-

rence price to guide stakeholders’ forecasts. This is why the

capacity mechanism rules proposed by RTE include provisions

that will facilitate the creation of such a platform.

7.1.3.1 Bilateral trades

The capacity mechanism rules suffice to allow bilateral trading

between mechanism stakeholders. Two stakeholders must sim-

ply agree on a trade and a price, and then carry out the transac-

tion and notify RTE, which will modify both parties’ positions in

the capacity certificate register accordingly.

In sum, the procedures involved in bilateral trades are similar to

those that exist in the energy market with the block exchange

notification (NEB) mechanism.

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MARKET FUNCTIONING: TRADING, TRANSPARENCY AND COMPETITION / 7

7.1.3.2 Development of an exchange platform

Examples observed in energy markets show that bilateral tra-

ding of long-term products is relatively illiquid. This can be a

major obstacle to the formation of a credible signal-price and

even make it difficult for stakeholders to find counterparties. It

seems necessary to have an organised market in place that will

concentrate liquidity through trading sessions in the capacity

market, thereby enhancing the quality of the signal-price.

The decree recognises the importance of having an exchange

platform for the capacity mechanism. It stipulates that if no such

platform is developed through private initiatives, and the Energy

Regulatory Commission recommends that one be created, the

Energy Minister can organise a call for tenders for this purpose.

During the consultation, EPEX Spot expressed an interest in set-

ting up an exchange platform for capacity certificates.

7.1.3.3 Interfacing with an exchange platform

Setting up an exchange platform will require determining how it

will interface with the capacity certificate register, which records

ownership of capacity certificates. To facilitate the development

of an exchange platform, the capacity mechanism

rules explicitly make this interface possible, but sti-

pulate that the exact scope and functioning of this

interfacing will be defined at a later date based on

work to be conducted jointly by RTE and the compa-

nies organising the exchange platform. This solution

avoids the potential problem of creating preliminary

constraints that could hinder or turn into obstacles to the deve-

lopment of an exchange platform.

The capacity mechanism rules create a robust framework for the trading of capacity certificates between market stakeholders. This framework is based on existing provisions for energy, with a central register maintained by RTE allowing transactions to be tracked. The future develop-ment of an exchange platform is factored into the capacity mechanism rules. Taken together, these provisions lay a solid foundation for the develop-ment of certificate trading.

7.2 Transparency of the mechanism

The capacity certificate market must be an efficient tool for

coordinating the efforts of mechanism participants. This will

be accomplished if the price at which certificates are traded

reveals relevant information. For this price to be meaningful,

stakeholders must have enough information about the state of

the system and market fundamentals at the start. This is why in

designing the rules, particular attention was paid to provisions

that could ensure that the mechanism functions in a transpa-

rent manner.

Transparency is needed with regard to the fundamentals of the

power system (i.e. the projected supply-demand balance for the

delivery year) and the actual functioning of the market (transac-

tion volumes and prices). The rules therefore include transpa-

rency measures focusing on:

> The physical underlyings of the mechanism, via the publica-

tion of an aggregate of the registers (§  7.2.1) and forecasts

of obligation volumes at the aggregate and individual levels

(§ 7.2.2);

> The functioning of the market, notably to provide visibility on

transaction volumes and prices (§ 7.2.3).

7.2.1 Publications relating to the registers

Since markets were opened to competition, the aggregated data

about the supply-demand balance outlook provided through

RTE’s Adequacy Forecast Reports have been indispensable to

the functioning of the deregulated power system. The need

for adequacy reports of this kind has since been recognised at

the European level and included in the European Commission’s

guidelines as a prerequisite to the implementation of a capacity

mechanism.

RTE’s annually updated Adequacy Forecast Reports already

provide a good deal of information about the supply-demand

balance outlook. They inform market stakeholders about the

fundamentals of the power system by providing an aggregate

view of forecast electricity supply and demand. These reports

are also a forward-planning tool in that they allow longer-term

scenarios of changes in the electricity mix and demand struc-

ture to be examined in the light of the targets set by French and

European authorities176.

176Additional information is made available every year through medium-term studies looking at the following winter or summer and the Electrical Energy Statistics.

166

The capacity mechanism rules call for the existing arrangement

to be strengthened through the regular publication of aggre-

gates of certified capacity levels and peak demand management

measures. For each delivery year, RTE will create and maintain

two registers, in addition to the confidential capacity certificate

register in which are recorded, in a secure manner, all transactions

involving the issuance, trading or destruction of certificates:

> The certified capacity register, listing all capacity certified;

> The peak demand management measure register, listing all

peak demand management measures reported by consu-

mers and suppliers, particularly any peak demand flexibilities

recognised through other mechanisms but not certified as

demand response capacity. RTE takes the data in this register

into account in calculating the overall obligation and makes

it public in a way that protects the confidentiality of commer-

cially sensitive data.

The publication of the aggregate data recorded in the regis-

ters will be key to the mechanism’s transparency and convey

information of a different nature than what is included in RTE’s

Adequacy Forecast Reports. Indeed, the latter are based on non-

binding data gathered from generators, whereas the certified

capacity registers will include data that is declared by genera-

tors to certify their capacity and can only be modified through

rebalancing. This should for instance facilitate the collection of

information about operators’ real prospects with regard to the

definitive closure or mothballing of certain facilities.

7.2.1.1 Publications relating to the certified capacity

register

The rules stipulate that the data in the certified capacity register

is to be made public. In concrete terms, this means that detailed

information will be made available about individual capacities --

volumes certified, technical characteristics, projected availability

and effective levels in previous years. Under the rules, the certi-

fied capacity register is to provide stakeholders with information

for the next four delivery years, as well as the last two, regarding:

> The total level of capacity certified for each technology;

> Details about individual certification levels for capacities of

more than 100 MW;

> Details about aggregated certification levels for capacities of

less than 100 MW.

The rules also stipulate that effective capacity levels must be

made available at these same scales for past years. Once the

mechanism is established, all market stakeholders will thus be

able to compare the certified capacity level of a capacity or tech-

nology with the effective level for previous years.

This publication will, in and of itself, be a powerful market moni-

toring tool since it will make it possible to gauge the credibility

of the information on record. With such measures in place, it

will be easy to detect any false information that is intentionally

conveyed (unrealistic data provided for initial certification with

subsequent rebalancing). If market manipulation is involved

and behaviours violate sector regulations on market abuse or

competition, punishments can be decided by the authorities in

charge of verification.

The information the capacity mechanism rules say must be

included in the certified capacity register are also required

under the provisions of Commission regulation 543/2013 of

14  June 2013 on submission and publication of data in elec-

tricity markets. Known as the “transparency” regulation, it aims

to make electricity markets more transparent by giving mar-

ket stakeholders access to a common set of data relating to

generation, transmission and consumption of electricity on

a European platform developed and managed by ENTSO-E.

The regulation provisions notably define this common set of

data and specify that data gathering is to begin late in 2014.

Market stakeholders (generators, consumers, etc.) must pro-

vide transmission system operators with different types of data

that is made public within the framework of the transparency

regulation. For instance, article 14 stipulates that transmission

system operators are to convey to the platform the sum of

generation capacity installed for all existing production units

with a power rating of at least 1 MW per production type, based

on information provided by generators. For capacity (existing

or planned) with a power rating of 100 MW or more, the trans-

mission system operator must also provide individual informa-

tion such as the name of the unit, installed capacity, voltage

connection level, etc.

Some provisions of the transparency mechanism require that

market stakeholders make public data that are also required

under the capacity mechanism rules. RTE is thus proposing that

the mechanism allow a pooling of procedures relating to data

provided for capacity certification and publication in the certi-

fied capacity register on the one hand and for publication within

the framework of the transparency regulation on the other.

This pooling ability offers advantages at different levels:

> It limits the number of declarations stakeholders have to make

and thus reduces the transaction costs the mechanism will

entail;

> It enhances the quality of consistency of the data published

by RTE.

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MARKET FUNCTIONING: TRADING, TRANSPARENCY AND COMPETITION / 7

7.2.1.2 Reporting changes in the parameters of capacity

certification

Capacity rebalancing does more than offer flexibility to capacity

operators. Only if rebalancing procedures are followed and reba-

lancing corresponds to the physical reality will the number of

capacity certificates available on the market accurately reflect

security of supply.

The decree stipulates that “an operator of certified capacity, or

a person mandated by it, informs the public transmission or dis-

tribution system operator to which the capacity is connected

of any changes in or additional information available about the

characteristics or operating conditions of that capacity suscep-

tible of impacting its projected availability during the PP2 peak

period.” (paragraph I of article 11).

Operators have two days to file a declaration if they become

aware of any such major change in operating conditions. Decla-

rations are required for capacities with certified capacity levels

exceeding 100 MW. Changes are considered to be major when

they cause the level of certified capacity to vary by 10%.

The capacity register take into account modifications in the fore-

cast availability of units, and new declarations are made public.

All mechanism stakeholders will thus be informed of changes in

the amount of certificates in issue.

7.2.1.3 Publications relating to peak demand

management measures

The capacity register referred to in the preceding paragraph

lists the capacity certificates available, including those offered

by demand-side operators that opt for explicit valuation through

the market (certification). Other publications focus on demand.

RTE will prepare forecasts of the overall level of certificates each

year (see paragraph below), but suppliers may also organise

measures with their customers, notably to reduce the obliga-

tion to which they are subject, and these measures may impact

national demand. These measures must also be reported to give

stakeholders more comprehensive information about the sup-

ply-demand balance.

Indeed, article 18 of the decree stipulates that RTE is to create

a “register, with information provided by suppliers and consu-

mers, listing measures intended to manage demand during

peak periods”. It goes on to say that the “information contai-

ned in the register that is necessary for the market to function

properly is made public and updated in a timely manner when

changes occur”.

Consequently, the rules stipulate that measures taken by sup-

pliers and consumers to reduce their consumption during peak

periods must be recorded in this register, particularly demand

flexibility at peak that is recognised through other mechanisms

but not certified as demand response capacity. Like the data in

the certified capacity register, this information is made public,

taking into account its commercially sensitive nature.

7.2.2 Publications relating to the capacity obligation

7.2.2.1 Publication of forecasts of overall certificate

levels

To help suppliers estimate their capacity obligation level, RTE

will publish its own forecasts of the overall obligation level, i.e. of

total demand in France.

A first forecast of the total number of certificates required for

the security of supply criterion to be met will be published at

the same time as the mechanism parameters, four year before

the start of the delivery year. The overall level of certificates will

be estimated applying the same methods and parameters and

those used to calculate the obligations of obligated parties.

This forecast will then be updated annually taking into account

the data in the certified capacity and peak demand manage-

ment measure registers, along with the most recent electricity

demand forecasts. Together with the information continuously

available through the certified capacity register, this forecast will

allow give mechanism stakeholders insight into the state of the

system and allow them to act accordingly. Suppliers will notably

be able to define and adjust their strategies for covering their

obligations.

7.2.2.2 Estimation of suppliers’ obligation

The efficiency of the market model proposed is based on the

assumption that suppliers are best placed to estimate the capa-

city obligation to which they will be subject. If this was not the

case, then the single buyer (capacity auction) model described

in §  2.3, under which public authorities estimate future capa-

city needs, could be justified. During the consultation, some

suppliers expressed doubts about their ability to estimate their

capacity need and concerns that this uncertainty could interfere

with the formation of the capacity certificate price. This debate,

a recurring theme throughout the consultation, boils down to

whether the economic optimum can be achieved with a decen-

tralised market structure.

168

Without seeking to provide a definitive answer to a ques-

tion that is central to economic and political theory, it is

important to determine whether, within the guidelines

adopted, there are mechanisms that can enable sup-

pliers to evaluate their capacity need. They have all the

information required to calculate their obligation: they

are in charge of the commercial policies that shape their

customer portfolios, and the parameters for calculating

the obligation (security factor, reference temperature

and gradient) are set before the delivery year. The one unknown is

the effective consumption of their customers, but this too can be

forecast. The situation is exactly the same for them as in the energy

market (suppliers anticipate extraction levels within their perimeter

to choose their procurement strategy and thus their transactions on

the forward, day-ahead and intraday markets), and they have tools at

their disposal: the incentive created by the mechanism to manage

demand during peak periods depends on it.

When the mechanism is first implemented, RTE will help obligated

parties understand how it functions by offering to calculate what

their capacity obligation would have been in past years based

on historical consumption data provided by them, applying the

parameters and rules published. This type of exercise requires

determining, ex post, peak periods that might not match those

that would actually have been defined. The approximation can

nonetheless help stakeholders better understand how their phy-

sical data translates into a specific number of capacity certificates.

RTE is also proposing to provide each obligated party with an

estimate of its obligation after the end of the delivery period,

based on available consumption data, and of the overall imba-

lance. These estimates will be provided after the end of the deli-

very period but before the transfer deadline for a term177, ena-

bling stakeholders to trade certificates on this basis to balance

their perimeters as obligated parties and thus limit any settle-

ment to which they may be subject for imbalances.

7.2.3 Publications relating to the functioning of the capacity market

The market monitoring measures implemented will allow CRE

to enhance the transparency of the mechanism by publishing

detailed data about the functioning of the mechanism and

exchanges. Indeed, the decree stipulates that:

II.  – At least once a year, the Energy Regulatory Commission

publishes, through all appropriate channels, statistical data rela-

ting to all transactions and public offers regarding capacity certifi-

cates and related products, including the volumes exchanged or

offered and prices178.

This data complements the physical data published by RTE to

provide stakeholders with a clear vision of the market and its

underlyings.

177The rules call for notification of the estimated obligation within 12 months of the end of the delivery period.

178Decree 2012-1405 of 14 December 2012, Article 17.

The purpose of the capacity certificate market is to reveal the value of contributions to security of supply. For mar-ket stakeholders to be able to assign a price to capacity certificates, they must have access to information about the general state of the system and the security of supply outlook. To this end, additional provisions have been introduced to make the market more transparent, beyond the existing mechanisms (Adequacy Forecast Reports), and correspond to best practices in terms of market transparency:

> The registers that include information about the physical state of the system will be made public (data provided at an individual level for units with power ratings of more than 100 MW, and aggregated otherwise);

> Each year, RTE will publish a forecast of the obligation level corresponding to total consumption in France, apply-ing the methods in the rules;

> RTE will assist obligated parties when the mechanism is first implemented by calculating, based on historical data, what their capacity obligation would have been in previous years;

> RTE will provide stakeholders with estimates of their obligations before the transfer deadline, based on available data;

> CRE will publish statistics on exchanges so that estimates can be made of the volumes traded or offered and prices.

169

MARKET FUNCTIONING: TRADING, TRANSPARENCY AND COMPETITION / 7

7.3 Competition in a decentralised capacity market

Creating a market that allows stakeholders to meet their capa-

city obligation will not suffice to make the mechanism economi-

cally efficient. How the market actually functions will also be key:

if some stakeholders have market power and abuse it to distort

prices, the market process will stray from the overall optimum.

Given the highly concentrated structure of the French electricity

market, particular attention was paid to competition issues in the

future capacity certificate market during the preparation of the

decree and the consultation of 2013. The decree was drafted

and the rules designed with these issues in mind (§ 7.3.1). None-

theless, it seems that the combination of a decentralised market

architecture and the ARENH scheme implemented in 2011 to

support the deregulation of the supply market in France require

a re-examination of the competitive structure of the capacity

certificate market (§ 7.3.2). The decree also introduced special

market monitoring procedures that will be that much easier to

put into practice thanks to the transparency of the registers,

proof that these considerations were taken into account from

the beginning of the mechanism design process (§ 7.3.3).

7.3.1 Competition and market power

Energy markets can only be efficient if there is free and undis-

torted competition between market participants. Various mea-

sures have helped to reduce the market power of incumbent

operators: the development of cross-border interconnections,

the harmonisation of methods for allocating rights to use inter-

connections, the development of implicit allocation methods

for exchange capacity (market coupling) and the harmonisation

of rules governing exchanges in different Member States. Ope-

rators’ positions and ability to influence markets are increasingly

being measured at the regional, and even European level.

Capacity mechanisms are being created in Europe under the

aegis of Member States that are responsible for their own security

of supply. This domestic focus has been a source of concern for

the European Commission, which expressed its reservations and

expectations in the guidelines published in November 2013179:

> Lack of competition in national energy markets could lead to

market manipulations that threaten security of supply:

Appropriate structural solutions to address problems of mar-

ket concentration leading to underinvestment should be

identified and implemented180.

> Public interventions to ensure security of supply could distort

competition at the national and transnational levels:

In concentrated markets, interventions to ensure generation

adequacy risk rewarding dominant incumbents for withhol-

ding strategies. In particular capacity mechanisms risk repli-

cating, or even embedding, problems of market concentra-

tion which exist in some Member States181.

There is a high degree of concentration in the French electri-

city market: incumbent operator EDF has a dominant position in

electricity generation and supply.

101. In 2011, EDF claims to have had 79.4% of electricity gene-

ration capacity in France. This includes 92% of nuclear capa-

city (EDF operates all nuclear power stations in France though

competitors hold drawing rights on some of them based on

industrial contracts), 66% of fossil-fired capacity (coal, fuel oil

and gas), 81% of hydropower capacity and 32% of renewable

energy capacities. Even excluding the capacity certificates

associated with ARENH rights, as provided for in the NOME Act,

it seems that EDF will still have a majority of capacity certificates.

102. At the same time, CRE’s market observatory showed that

in 2011, EDF and public local distribution companies supplied

94% of residential consumption and 78% of consumption at

non-residential sites (EDF accounts for a very large share of

this total). EDF will consequently by far need the most capa-

city certificates182.

This situation is mainly a reflection of the energy policy choices

France made in the past, which gave the incumbent operator a

nuclear power generation fleet that is competitive at the natio-

nal and European levels. However, this does not means that its

dominant position is abused:

> Market concentration is measured by the number of stake-

holders in a market and their respective market shares. This

measurement can be taken on the supply or the demand side;

> A stakeholder’s market power refers to its ability

to cause market prices to move away from the

level that would be achieved in a market charac-

terised by pure and perfect competition, for its

own benefit;

> The exercise of market power refers to a situation

where a stakeholder takes advantage its market

power. This usually detracts from the collective

179[EC, 2013a]

180[EC, 2013a]

181[EC, 2013a]

182[Competition Authority, 2012a]

170

well-being and enhances the profits of the stakeholder in

question. Competition law only punishes the abuse of domi-

nant position183.

The two do not always go hand in hand. A market can be

concentrated without the company or companies with signifi-

cant market share necessarily having market power, especially

if regulations are in place to keep the market competitive. Simi-

larly, market manipulation can be seen in markets with relatively

low concentration levels, as evidenced in studies focusing on

the “pivotal” role played by some firms in specific instances, such

as the California crisis of 2000-2001184. Lastly, market power is

only a potentiality, and will not necessarily be exercised: just

because a stakeholder’s position would allow it to distort com-

petition does not mean it will do so.

While it seems clear that greater vigilance is required with regard

to the design of mechanisms that could reinforce dominant

positions, this should not be considered sufficient reason to

avoid implementing such mechanisms. First, there are already

specialised authorities in place to evaluate market functioning

and deal with abuses of dominant position. Second, the regula-

tory framework in France already includes provisions intended

to promote competition: the Regulated Access to Incumbent

Nuclear Electricity (ARENH) scheme offers a structural and

appropriate solution to market concentration in France185.

Lastly, the assessment by public authorities, for instance in the

Poignant-Sido report, did not focus on the possibility that the high

level of concentration in the French market could lead to strate-

gic underinvestment. On the contrary, the workgroup focused on

how to fairly divide responsibility for investments in peak gene-

ration facilities that are not profitable in the energy market des-

pite the positive externalities they create, a responsibility that has

hitherto been implicitly borne by the incumbent operator.

The purpose [of a capacity obligation] is to distribute

responsibility for insurance against the risk of a gene-

ration shortfall186.

On the other hand, the European Commission’s

concerns suggest that a close look must be taken

at how the provisions proposed could, once imple-

mented, allow strategic behaviours, particularly capa-

city withholding. It should be recalled that a portion of

the Competition Authority’s review of this question in

April 2012 focused on the robustness of the mecha-

nism with regard to capacity withholding strategies.

It found that the introduction of a safety net mechanism created

capacity withholding risks by permitting opportunistic behaviours

by generators (artificially minimising the availability of their gene-

ration capacity to activate the mechanism), and suggested that

operators not be allowed to commit to availability levels below

their historical average to prevent strategic behaviours.

These concerns have been taken into account. The safety net

mechanism is indeed reserved for exceptional circumstances,

and the procedures in place will make it easy to see if opera-

tors are significantly underestimating the future availability of

their capacity. Indeed, the transparency of the certified capacity

register will allow all parties to identify any capacity withholding

strategies, including preventively by comparing the amount of

capacity certified for a given year to levels from previous years.

Another concern is whether the capacity obligation could create

entry barriers in an already complex regulatory environment. The

certification methods proposed in the rules (neutrality between

all technologies) ensure equal treatment for all capacity operators

(generation, demand response or storage) and prevent forms of

selection that could exclude new entrants. In the supply market,

the capacity obligation adds another layer of complexity that

could be seen as an obstacle for new entrants, or as an oppor-

tunity: it applies to all stakeholders, but each supplier can forge

its own strategy for covering the obligation. This new facet of the

supply business creates opportunities for stakeholders to dif-

ferentiate their offerings and stimulate competition. Lastly, the

verification procedures proposed ensure that stakeholders are

not subject to excessively onerous declaration requirements and

take special care to avoid imposing a segmentation of demand

response entities, as discussed in sections 5.6 and 5.7.

7.3.2 Competition under the capacity mechanism

Market power is hard to quantify as many factors must be taken

into account, and some of them might not be measurable. It is

nonetheless possible to select an indicator of the competitive

situation, a simplified one necessarily, and to consider the effects

of the market architecture adopted with regard to this indicator.

183Article 102 of the TFEU and article L. 421-2 of the French Commercial Code.

184[Wolak, 2003]

185Appropriate structural solutions to address problems of market concentration leading to underinvestment should be identified and implemented [EC, 2013a].

186[Poignant-Sido, 2010]

The French electricity market is highly concen-trated and this would be problematic if it resulted in market manipulation. However, it has not led to underinvestment and thereby not created any security of supply risk. Special attention was nonetheless paid to this situation in designing the capacity mechanism rules.

171

MARKETFUNCTIONING:TRADING,TRANSPARENCYANDCOMPETITION / 7

For instance, market concentration is a traditional measurement

for assessing competition. This type of analysis can be conduc-

ted on the capacity certifi cate market, though the specifi cs of

the market architecture must be taken into account. In the sec-

tions below, the eff ects of two aspects of the market architec-

ture on the structure of the market - its decentralised nature

and the ARENH scheme - are analysed.

7.3.2.1 Eff ects of a decentralised architecture on the

market’s structure

In a centralised market, a stakeholder’s market power depends in

large part on its market share, or in other words its share of the

total capacity certifi cates issued for a given delivery year. With a

capacity auction scheme modelled after the mechanisms in place

in the Eastern United States, market concentration would thus be

largely determined by the market shares held by generation and

demand response capacity operators. In a decentralised market,

a vertically integrated company must also cover its own needs: as

such, its potential market infl uence is primarily determined not by

its absolute position but rather by its net position.

The signifi cance of net positions is one eff ect often cited when

vertical integration is a factor:

In evaluating proposed horizontal mergers in vertically sepa-

rated markets, antitrust agencies (and courts) focus primarily

on […] the concentration levels in the industry prior to the

merger and the predicted change in concentration levels

due to the merger, where concentration is measured using

the HHI. […] [Generalizing] the analysis to vertically integrated

markets suggests that analysts use the fi rms’

net positions to measure the eff ects of market

power. As noted above, zero net demand causes

no ineffi ciency187.

This eff ect is particularly pronounced in France,

given the incumbent operator’s share of the gene-

ration and supply markets. Estimated on the sole

basis of certifi ed capacity, the concentration level is

very high. However, if the incumbent’s net position

is considered, then its weight in the market is relative since it

also has a signifi cant share of the supply market. In this regard,

the decentralised market architecture is particularly suited to

conditions in the French market, as some academic studies

have noted:

Considering the specifi c characteristics of the French electricity

market, with a high degree of vertical integration, and the way

competition was organised by the NOME scheme, […] the criti-

cism directed against [the decentralised obligation] is not valid188.

The decentralised architecture and vertical integration also

impact diff erent stakeholders’ incentives. A stakeholder that has

capacities will not necessary want to see the capacity certifi cate

price increase: it can actually have more to lose than to gain if it

is a net buyer.

Vertically integrated wholesalers, or those with long-term

contracts, have less incentive to raise wholesale prices […].

Findings suggest that vertical arrangements dramatically

aff ect estimated market outcomes. Had regulators impeded

vertical arrangements (as in California), simulations imply

vastly higher prices than observed and production ineffi cien-

cies costing over 45 percent of those production costs with

vertical arrangements. We conclude that horizontal market

structure accurately predicts market performance only when

accounting for vertical structure189.

These considerations support the use of a market concentra-

tion indicator that takes the eff ects of vertical integration into

account.

7.3.2.2 Measures to stimulate competition

The NOME Act190 provided a structural response to competi-

tion issues in the French electricity market by introducing, from

2012, the ARENH mechanism (Regulated Access to Incumbent

Nuclear Electricity). Developed in cooperation with the European

Commission, this scheme is designed to promote competition

187[Hendricks & McAfee, 2010]

188[Finon, 2011]

189[Bushnell et al., 2008]

190Law 2010-1488 of 7 December 2010 on the New Organisation of the Electricity Market.

Awordaboutthisdiscussionofmarketpower

The reasons why market power exists can be nume-

rous and complex, and they cannot be covered solely

by analysing market concentration in terms of absolute

or net positions. Other factors can include the pivotal

role played by certain fi rms in the market, the elasti-

city of supply and demand curves and the existence

or absence of entry barriers. The indicators calculated

in the sections below do not take these consideration

into account, and thus only off er a partial picture of the

competitive situation. They are not meant to be subs-

tituted for a real analysis of competition in the French

electricity market, but rather to illustrate, through

simple orders of magnitude, the consequences of the

architecture choices made for the capacity market.

172

in the supply market by giving alternative suppliers direct and

regulated access to electricity generated by the incumbent’s

historical nuclear fleet on economic terms equivalent to those

of the incumbent operator:

To ensure that consumers are free to choose their

electricity supplier, and that pricing across the

country and all consumers benefit from the compe-

titive pricing of power generated with the historical

nuclear fleet, it will be possible, during a transitional

period defined in article L. 336-8, for all operators

supplying final consumers in continental France, or

system operators for their losses, to have regulated

and limited access to nuclear power generated by the

incumbent at the nuclear power plants mentioned in

article L. 336-2.

This regulated access is granted on economic terms

equivalent to those resulting for Électricité de France

from the use of the nuclear power plants mentioned

in the same article L. 336-2191.

The ARENH scheme shapes how the French elec-

tricity market functions if the ARENH price is com-

petitive relative to the wholesale market price, i.e.

if nuclear power generated with the incumbent

fleet is competitive relative to electricity generated

in Europe: in this case the market functions as if all

suppliers had a form of vertical integration between

upstream and downstream operations through the

property rights they hold to a portion of incumbent

nuclear electricity.

A similar effect can be seen with the capacity

mechanism: the decree of 2011 specifying how

the ARENH scheme functions indicates that an

alternative supplier that exercises its ARENH rights

will also have access to the corresponding capacity

certificates192:

The [ARENH] product includes the generation capa-

city certificate, as defined in article 4-2 of the afore-

mentioned law of 10  February 2000, corresponding

to its profile.

This is a particularly important point with regard to

competition, since it means that all suppliers, inclu-

ding those that do not operate any capacity, benefit

from a vertical integration effect through ARENH without bea-

ring any more costs than they did before the capacity mecha-

nism was implemented.

In concrete terms, there is no guarantee that the incumbent

operator will be a net seller of capacity certificates, whereas

some alternative suppliers with capacity will be “long” on cer-

tificates when the mechanism first takes effect. Over the longer

term and provided that the ARENH price remains competitive,

suppliers’ net positions will be determined by the temperature

sensitivity of their customer portfolios with regard to the ARENH

capacity rights held.

The capacity value associated with the ARENH can be made

available in two ways:

> The first involves the transfer of “physical” capacity certificates

from EDF to alternative suppliers, which could then use these

certificates to meet all or part of their obligation;

> The second involves financial transactions: EDF would hold all

capacity certificates allocated to the nuclear plants and sell

them on the capacity market, with the proceeds passed on to

alternative suppliers in proportion to their ARENH rights.

The decree instituting the capacity mechanism tasks the Energy

Regulatory Commission with proposing specific procedures to

the Minister. When this report went to press, CRE’s intentions in

this area were not known. If it opted for a financial treatment

of ARENH rights, the market would be more concentrated, but

probably more liquid as well. Measuring these conflicting effects

from a competition standpoint is complex and would require an

in-depth analysis that RTE did not conduct. In the rest of this

report, only a system involving the “physical” transfer of capacity

certificates is considered, as the simplified indicators used are

meaningful with this assumption.

7.3.2.3 Simulations of concentration in the capacity

market

The decentralised organisation of the capacity mechanism and

initial allocation of capacity certificates to alternative suppliers

provided for under ARENH have combined effects on market

concentration. These effects were studied through a simulation

wherein the certification and obligation levels of all capacity mar-

ket stakeholders, suppliers and capacity operators, were calcula-

ted for the years 2006 to 2011193. Market concentration is measu-

red using the Herfindhal-Hirschmann Index (HHI)194.

The study focused first on the effect of the decentralised mar-

ket architecture with vertical integration. The HHI is calculated

191L. 336-1 of the Energy Code.

192Decree 2011-466 of 28 April 2011 setting out the rules for access to historical nuclear energy, Article 1, V.

193Calculations have been simplified and do not correspond exactly to the final capacity mechanism rules. However, the results suggest orders of magnitude, since the simplifications are not unidirectional. Simulations were carried out a time when all rules and parameters of the French capacity mechanism were not known with certainty. The most significant approximations calculated for the purposes of this study are: the peak periods considered are placed within the calendar year on the winter days when demand is highest, with a maximum of five days in March and November; accounts are separated for capacities subject to purchase obligations; hydro capacities are overestimated (technical limitations not factored into the study), some capacities connected to the distribution grid are not allocated. The orders of magnitude shown in the results are thus significant, but must be considered as estimates rather than exact values.

194The Herfindhal-Hirschmann Index, or HHI, is a measurement of market concentration that indicates the degree to which a market shows one characteristic of pure and perfect competition: market atomicity. The HHI is calculated as the sum of the squares of the market shares of each participant (expressed as a percentage).

173

MARKETFUNCTIONING:TRADING,TRANSPARENCYANDCOMPETITION / 7

based on stakeholders’ net positions, or in other words the dif-

ference between the capacity certifi cates allocated to their cer-

tifi ed capacity and their capacity obligations. Integrated compa-

nies are therefore considered net buyers or sellers, depending

on the respective weightings of their generation and supply

activities.

Two slightly diff erent market concentration indicators are com-

pared: an HHI calculated using absolute positions and an HHI

based on net positions. Neither measures the competitive situa-

tion perfectly, but the comparison does illustrate how taking

into account the eff ects of vertical integration in a decentra-

lised market makes it necessary to reconsider how competition

actually works.

The second eff ect studied is that of the ARENH, which reba-

lances stakeholders’ positions by enhancing the vertical integra-

tion of new entrants. Its impact is estimated by comparing two

HHIs, one with and one without ARENH, taking net positions into

account.

Net sellers of capacity certifi cates are considered separately

from net buyers. This gives a better indication of market power,

which is mainly the result of a stakeholder’s net position in the

market once its own needs have been covered. A stakeholder

that has exactly enough capacities to meet its own needs will in

theory not be able to infl uence the market price since it will not

be buying or selling.

With this approach, it is possible to compare the respec-

tive eff ects of the decentralised architecture and the

ARENH scheme on market concentration in France’s

situation. Looking at the market concentration of sellers

of capacity, we can see that, on average195:

> A decentralised market reduces HHI market

concentration by 3,000  points compared with a

centralised market;

> The existence of the ARENH scheme reduces the

HHI of the capacity market by 2,400 points.

These eff ects are cumulative. The combination of a decentra-

lised market with the ARENH regulation to increase competition

yields a picture of market concentration that is diff erent from

the initial perception.

Having a decentralised architecture and the ARENH scheme in

place to strengthen competition yields market concentration

levels that are generally considered acceptable. In the chart

above, the black line corresponds to a HHI of 2,500, conside-

red the limit between high and moderate concentration levels

under the defi nition applied in the United States196. The HHI of

net sellers of capacity certifi cates dips in one year below 2,000,

this being the level below which the European Commission says

it is unlikely to identify competition concerns197.

As mentioned above, the indicators presented here do not allow

conclusions to be drawn about the real state of competition in

195Based on aforementioned hypotheses and averaged results from data for 2006-2011.

196[DOJ, 2010]

197Guidelines on the assessment of horizontal mergers under the Council Regulation on the control of concentrations between undertakings, paragraphs 16, 19 & 20.

HH

I

High concentration

Moderate concentration

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2006 2007 2008 2009 2010 2011

ARENH effect

Decentralised marketand vertical integration

Figure 77 – Illustration of the eff ects of market architecture and the ARENH on concentration in the capacity market based on past data

HHI Capacity operators

HHI Net sellers w/o ARENH

HHI Net sellers 

HHI Net buyers w/o ARENH

HHI Net buyers 

174

the French electricity market. On the other hand, they do show

that the market architecture chosen has an impact on effective

competitive conditions.

7.3.2.4 Anticipated trends in market concentration with

the development of demand response

The market concentration estimates presented above are based

on past data. Anticipating future trends requires taking into

account the development of new resources, notably demand

response, and other measures that have a dynamic impact on

demand, particularly during peak periods in winter.

This is an important point since a highly concentrated market

will be less susceptible to the exercise of market power if it can

be easily challenged in the absence of entry barriers. The speci-

fic characteristics of certain types of demand response (notably

industrial), some of which may have lower fixed costs than gene-

ration capacities, place them in a good position to challenge

dominance in the capacity market. This is in keeping with the

objectives of the mechanism outlined in chapters 1 and 2: the

French capacity mechanism must allow demand response to

play its rightful role in ensuring that there is adequate capacity

for supply and demand to balance.

The architecture of the French electricity market has evolved

recently to allow the explicit participation of demand response

in energy markets, including demand response aggregators198.

Consumers and aggregators thus have access to all electricity

markets (balancing mechanism since 2003, “rapid and comple-

mentary reserves” since 2010, wholesale electricity

market since 2013 and system services as of 1 July

2014). There are no restrictions on this participa-

tion since the agreement of site suppliers is not

required199.

The goal in creating this framework for rewarding

demand response is to encourage the development

of its potential and the role of demand-side opera-

tors in France. Their participation in electricity mar-

kets should help reduce concentration in the energy

market and the capacity market, in which demand

response capacities can also participate explicitly200.

The introduction of the capacity mechanism can

in turn boost competition in other markets, inclu-

ding the energy market. Encouraging the develop-

ment of capacities other than energy production by

rewarding their contribution to security of supply

can help diversify the energy mix and the structure of the mar-

ket. The high capacity value of demand response, the potential

of which reaches its height during peak periods, will stimulate

the development of capacities that will also participate in the

energy market.

7.3.3 Monitoring of the market’s functioning

7.3.3.1 The need for monitoring

The preceding sections outlined competition issues in the capa-

city market and provided evidence that in the final analysis, a

decentralised mechanism, taken together with ARENH, a struc-

tural measure that strengthens competition in the supply mar-

ket, creates a much more complex competitive situation than

what is often described.

In practice, assuming that ARENH-related transfers will be “phy-

sical”, all suppliers will be allocated enough capacity certificates

initially to meet all or part of their obligation. In other words, the

capacity market could function with all stakeholders starting out

with more or less balanced positions: none would have to buy all

of the certificates needed to cover its needs, a factor that drasti-

cally reduces the opportunities for exercising market power.

However, in this scenario, trading volumes are likely to be low,

and this will make the capacity certificate market less liquid. In

this sense, the physical transfer of capacity certificates associa-

ted with ARENH rights will reduce certificate trading volumes,

whereas a financial treatment would increase it. Under these

conditions, it seem necessary to set up an exchange platform, as

mentioned earlier, to concentrate liquidity and make it easier for

a credible reference price to be formed. A geographic extension

of the market would also enhance liquidity, which is why efforts

198These changes are discussed in chapters 1 and 10 of this report.

199The demand-side operator's regulated access to the consumer is based on Competition Authority recommendations and the implementation by RTE, under the supervision of CRE, of the new organisation of the regulatory framework for demand response called for in the Brottes Act [Competition Authority, 2012b], [Competition Authority, 2013]

200The participation of demand response in energy markets is discussed in detail in chapters 1 and 10 of this report.

Taking into account the decentralised architec-ture of the mechanism and the vertical integra-tion effects resulting from the ARENH scheme gives a more accurate picture of the capacity market. The competitive situation in the capac-ity market thus appears more favourable than initially thought.

Moreover, competition in the energy and capacity markets will be mutually strengthened, notably through the development of demand response. The French capacity mechanism could thus allow demand response to play a key role in “rounding out the capacity equation”, making it harder for stakeholders to exercise market power while also reducing costs.

175

MARKET FUNCTIONING: TRADING, TRANSPARENCY AND COMPETITION / 7

undertaken with other Member States to promote common

approaches are so important.

Nonetheless, capacity certificate trading will have to be closely

monitored in the beginning to ensure that the mechanism is

functioning properly.

With this in mind, the regulatory authority decided from the out-

set to give the regulator the resources to efficiently monitor the

functioning the capacity certificate market. It notably stipulated

that all transactions involving capacity certificates were to be

notified to CRE, a requirement that will cost almost nothing if

the notification procedure is coupled with the capacity certifi-

cate register recording all exchanges of certificate:

The procedures for collecting this data are defined by the

Energy Regulatory Commission after prior consultation with

the public transmission system operator201.

7.3.3.2 Efficiency in detecting market manipulation

How efficiently the capacity certificate market is monitored

should be considered in the light of market manipulation oppor-

tunities. As indicated earlier, the concerns voiced by the Com-

petition Authority in April 2012 and reiterated in the European

Commission’s recent Communication focus specifically on the

exercise of market power by the incumbent operator and pos-

sible capacity withholding strategies.

Where the incumbent operator is concerned, specific pro-

visions allow CRE to get information about the exchanges it

makes, including the cost of internal transfers. Decree 2012-

1405 of 14 December 2012 provides for two different entities

for capacity operators (capacity portfolio manager) and the

obligation (supplier). This provision, which applies to all stake-

holders, enables monitoring of vertically integrated companies.

As specified in article 17 of the decree, CRE must be notified of

exchanges conducted between these entities:

Any person that transfers a capacity certificate or related pro-

duct, or makes a public offer to buy or sell capacity certificates

or related products, informs the Energy Regulatory Commis-

sion, directly or through a third party, of the characteristics of

the transfer or offer, particularly the price202.

As for the mechanism’s vulnerability to capacity withholding

strategies, the transparency measures adopted in the rules for

the registers should make it easy for market stakeholders or

monitoring authorities to detect any abusive practices. In this

regard, the transparency of the registers will be key to resolving

the issue discussed in chapter 5 about stakeholders’ ability to

rebalance at zero cost. During the consultation, some stake-

holders suggested that while the ability to rebalance at zero

cost before the delivery year gives virtuous operators the flexi-

bility needed to manage their capacity commitments, it could

also create inexpensive market manipulation opportunities for

others. RTE took this point very seriously: the solution it adop-

ted in the capacity mechanism rules was to insist on maximum

transparency (declarations for capacities of more than 100 MW

recorded including names and made public, regulation of “signi-

ficant” rebalancing volumes representing more than 10% of cer-

tified capacity) rather than introduce more complexity, for ins-

tance by making an operator’s ability to rebalance conditional

upon its market power.

Likewise, there is no plan to require that capacity operators’

commitments be based on availability levels from previous

years, as the Competition Authority suggested in 2012, since

this could distort the incentives created by the mechanism,

which are currently based exclusively on commitments. There

is no need for such regulation mechanism in the energy

market, for instance, to ensure that supply commitments are

coherent. However, past availability data will be made public

for each capacity, and CRE will be able to use them in monito-

ring the market.

Taking into account these measures, which are stipulated in the

decree and put into practice in the rules, CRE estimated in its

opinion of April 2012 that it was in a position to ensure that the

capacity market functions properly:

CRE estimates that its market monitoring tasks, both upstream –

where it can track and monitor all transactions, including those

relating to self-supply – and downstream – where it can ensure

that suppliers’ commitments are consistent with

their purchasing costs – will allow it to ensure that

the capacity mechanism does not interfere with

competition in the downstream market.

If a dysfunction is observed, CRE will propose

to the Minister any measures necessary to gua-

rantee that competition is effective, both in the

upstream and downstream markets203.

The Energy Regulatory Commission will regularly

submit reports on its monitoring activities to the

Energy Minister:

201Decree 2012-1405 of 14 December 2012 relative to the contribution of suppliers to security of electricity supply and to the creation of a capacity obligation mechanism in the electricity sector, article 17.

202Decree 2012-1405 of 14 December 2012, Article 17, paragraph 1.

203[CRE, 2012]

176

7.4 Conclusions

The capacity obligation is designed to safeguard security of

supply, and the capacity market associated with it is intended

to minimise the cost. This will be an economically efficient archi-

tecture for delivering a public good (security of supply) provided

that transaction costs are sufficiently low. The trading of capa-

city certificates and the functioning of the market are thus extre-

mely important, and their efficacy depends on three factors: the

existence of a robust framework to govern exchanges, a high

degree of transparency, and effective competition.

First, the market is designed to function in such a way as to

facilitate exchanges and give stakeholders confidence in the

“capacity certificate” product. Since the mechanism parameters

are published ahead of time and remain stable throughout the

mechanism term, trading can take place in a stable regulatory fra-

mework and the value of the product cannot be modified by the

intervention of forces external to the market. Though it creates

greater uncertainty when the parameters are being set, this pro-

vision appears indispensable for the market to function properly.

Moreover, the fact that the movements of capacity certificates are

recorded in a register kept by RTE makes the product credible. In

this regard, the architecture adopted is similar to that

of the energy market: it enables bilateral trades and

leaves room for the creation of an exchange platform

on which supply and demand can be matched. This

organisation of exchanges appears necessary given that the mar-

ket is unlikely to be very liquid.

As regards transparency, various provisions allow stakeholders

to participate in the capacity market with full knowledge of the

security of supply outlook. In addition to the Adequacy Forecast

Reports RTE already publishes, they will have access to data

from two registers maintained by RTE:

> The certified capacity register, listing all certified capacities

individually;

> The peak demand management register, listing all demand-

side measures that impact the mechanism.

In addition, RTE will help obligated parties become familiar with

the mechanism and send them estimates of their obligation.

Lastly, CRE will publish data on the market’s functioning and

transactions, helping stakeholders to assess the prices observed

in the market.

The last requirement for the market to function properly  –

effective competition  – was undoubtedly the biggest source

of concern about the mechanism both in France and Europe.

Given the high level of concentration around the incumbent

operator in the French electricity market, some feared that there

would be no real competition in the capacity market, and that it

could even have harmful consequences for the supply market.

I. No later than one year after the capacity mechanism rules

are published, and at least once a year after that, the Energy

Regulatory Commission submits to the Energy Minis-

ter a report on the functioning of the capacity certificate

market204.

7.3.3.3 Public offerings

Lastly, to prevent potential capacity withholding strategies,

article 6 of the NOME Act stipulates that:

All certified capacity certificates must be made available to

suppliers, either directly or indirectly, to allow the obligation

mentioned in the same article to be met. Capacity certificates

held by a supplier beyond what is needed for it to meet its

obligation must be offered for sale publicly.

To put this provision into practice, the capacity mechanism rules

call for public offerings to be organised once obligated parties

have received the final notification of their capacity obligation.

204Decree 2012-1405 of 14 December 2012, article 19.

Measures included in the market architecture to strengthen competition play a preventative role, but the functioning of the market must also be closely monitored by CRE. Market monitoring will be that much more important since the market is not expected to be very liquid. The monitoring and transparency measures set out in the decree and the rules complement one another to form what is considered a sufficient framework, based on current needs, as the publication of the infor-mation in the registers should allow any suspi-cious behaviours to be easily detected.

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MARKET FUNCTIONING: TRADING, TRANSPARENCY AND COMPETITION / 7

A more careful analysis of the market structure nonetheless

paints a different picture of the risk that market power will be

exercised. Factoring in the decentralised nature of the market,

and the vertical integration effects created by the measure-

ment of stakeholders’ net positions, market concentration will

be lower than initially thought. The benefits alternative suppliers

will derive from the capacity certificates associated with ARENH

rights will also significantly reduce market concentration. In this

regard, the risk of market power being exercised seems limited.

Thanks to the verification and monitoring procedures that are

integrated into the mechanism through the certified capacity

register, the regulator will be able to detect any abusive prac-

tices and track all exchanges.

Lastly, it would be limiting to view the capacity mechanism solely

as a threat to competition in the electricity market. By encou-

raging the development of demand response, it will allow new

capacities to compete with existing ones, including in energy

markets. Moreover, by adding another dimension to the supply

business and creating new activities, it will favour a diversifica-

tion and differentiation of offerings, depending on the strategies

stakeholders adopt to meet their obligation (a similar philoso-

phy is applied in the mechanism proposed by the BDEW in Ger-

many). In a word, this new market mechanism will be a source of

many opportunities for the most efficient stakeholders.

178

8. CAPACITY MECHANISM IMPACT ASSESSMENTS

There has been a gradual paradigm shift in public decision-

making in recent years, both in France and Europe. Preliminary

assessments are now required to ensure that planned measures

are necessary and proportionate, and once in effect, these mea-

sures are subject to regular evaluations in case modifications are

required.

The capacity mechanism is being introduced against this backdrop.

Where the initial impact assessment is concerned, RTE’s pro-

posed capacity mechanism rules include an analysis of the

cost to consumers. Provisions are also in place to allow the

mechanism’s functioning to be gradually adapted as feed-

back is received, as the decree of December 2012 calls for the

Energy Regulatory Commission to regularly prepare reports on

the functioning and integration of the capacity mechanism.

Based on these reports and the assessments RTE will conduct in

accordance with the rules, it will be possible to adjust, adapt or

even reform the mechanism. In a word, the existing regulatory

framework and proposals for putting it into practical application

are intended to achieve compliance with best practices in the

area of public policymaking.

Many studies cited in the previous chapters aim to quantify the

effects of decisions made about different mechanism parame-

ters. While they provide useful information, it is also necessary

to evaluate the aggregate effects the provisions proposed will

have on the functioning of the energy market and investments.

This evaluation allows the cost of the mechanism to be mea-

sured against its security of supply benefits for the consumers

that finance it. A specific difficulty arises with this type of analy-

sis: to be accurate, it must take into account all of the capacity

mechanism parameters, but these are still being determined

through a consultation with stakeholders and are thus changing

frequently. Moreover, experience has shown that when models

of the functioning of capacity mechanisms are produced hastily,

the results are unusable since the situations modelled do not

correspond to reality.

This chapter takes account of this dichotomy. It begins by pres-

enting the challenges posed by detailed modelling of the func-

tioning of capacity mechanisms (§  8.1) and then outlines the

difficulties associated with dynamic aspects, underscoring how

the analyses currently being considered at the European level to

model the French mechanism need to be expanded (§ 8.2). The

next section presents aspects of the initial impact assessment

focusing on the financial consequences for consumers of the

mechanism’s implementation, on an all other things being equal

basis (§ 8.3). The last section is devoted to putting into context

the results of the research efforts under way, which will serve

as a basis for the different steps in the implementation process

provided for in the decree (§ 8.4).

8.1 Challenges associated with detailed modelling of how capacity mechanisms function

8.1.1 Analysis of technical parameters

During the consultation on the rules, special attention was paid

to quantifying the effects of the technical provisions RTE was

proposing. Numerous studies discussed in chapters 4, 5 and 6

allow the impact of the different aspects of the mechanism to

be quantified. All in all, some 30  studies and simulations were

carried out, and the results were presented during the consulta-

tion to inform the discussions.

Some of the most significant results of these studies were:

> Taking temperature sensitivity into account in the parame-

ters for calculating the capacity obligation ensures that the

obligation is borne by temperature sensitive consumers,

which indeed represent the biggest risk to the power system.

Large consumers that can reduce load during peak periods

consequently have a zero obligation;

> A targeted PP1 period provides an incentive to reduce load

during peak periods, when security of supply is at risk. This

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CAPACITY MECHANISM IMPACT ASSESSMENTS / 8

increases competition between capacity suppliers that can

respond to the needs of the power system, and thus helps

lower costs;

> Similarly, the value of demand response capacity is maximised

by defining a short PP2 period.

8.1.1.1 Use of a simulator during the consultation

In addition to being a forum for sharing technical results, the

consultation was enhanced from the outset by an original fea-

ture: market stakeholders were given access to a free, calibra-

ted and open source supply-demand balance simulator205. RTE

developed this simulator206 specifically for the consultation, to

allow each stakeholder to assess the impacts of the key choices

made regarding the certification method and the impact of

parameter choices.

RTE issued nine free user licences to market stake-

holders and administrations. The tool illustrated the

benefits of measuring a capacity’s contribution to

reducing the shortfall risk based on availability rather

than solely on installed power. It also supported the

choices made with regard to the parameters used in

the certification method, especially the considera-

tion of technical and management constraints that

affect capacities’ contribution to reducing the shortfall risk.

As a follow-up, a new simulator, in the form of a serious game,

will be made available to consultation participants, authorities

and other interested parties so they can see how the market

will function, from the certification process through to the post-

delivery year period (§ 8.4.1).

205The simulator was made available on request by RTE with free licences for the purpose of the consultation.

206The simulator is called CLAC (Capacity Lab – Aide à la Certification).

BASIC MODULEOptimisation

in period T

ADVANCED MODULE

Optimisationover T1

Optimisationover Ti

Optimisationover TN

LT > STDivision into sub-scenarios

T > T1 … Ti … TN

LT analysis

Model 1

Model 2

ST analysis

Results processed

Model parametersST

Simplified, fictional mix

N contingency scenarios

Setting of LT parameters

Figure 78 – Functional diagram of the simplified open source supply-demand balance simulator

8.1.2 Assessment of the aggregate effects of the mechanism

Analysing the economic impacts of the mechanism requires

taking a step back from the technical discussions relating to

the obligation, certification and settlement processes and

evaluating the consequences of the mechanism’s aggregate

effect on different categories of stakeholders to inform the

public authorities charged with making decisions about the

proposals.

To be thorough, this impact assessment must compare (i) the

charges specifically associated with the capacity obligation

borne by consumers (costs) and (ii) the effects of the security

of supply protection provisions (benefits) in two alternative

scenarios:

> A scenario with no capacity mechanism in place: consumers

are exposed to the market price in the same was as today (fac-

toring in the complexity of the regulatory framework). Capa-

cities do not generally receive any specific remuneration for

contributing to security of supply. The energy price is the

economic signal relied upon to optimise both the short-term

functioning of generation resources and long-term invest-

ment decisions;

> A scenario with a capacity mechanism introduced in accor-

dance with the rules proposed by RTE.

180

There is nothing simple about this type of analysis.

First (1), for the “no capacity mechanism” scenario to be a cre-

dible reference, it has to model in detail how the existing market

functions. This poses several problems.

With the way power systems are currently organised in Member

States, some capacities already benefit from a form of capacity

remuneration through different means (particularly by being

included in the reserves system operators use for real-time

balancing) while others receive subsidies that disconnect them

from price signals: a model of the existing market’s functioning

cannot disregard these realities or their impact on the market.

Moreover, the market’s functioning in periods of tight supply

does not follow the theoretical principles (real, albeit infrequent,

extreme price spikes during which time supply to consumers

depends on their marginal willingness to have power supply

interrupted) supporting the energy-only model’s ability to gua-

rantee the optimal remuneration of generation and demand

response capacity. In practice, this form of market organisation

has consequences for investment structures (underinvestment

in peak versus base-load capacity) and security of supply (load

shedding), and these consequences are borne by consumers,

either through what they pay for supply or through a level of

security of supply that fails to meet the objective set by public

authorities.

Second (2), it is difficult to quantify the effects the proposed mar-

ket models could have over the medium or long terms, as dyna-

mic analyses of the functioning of complex markets subject to

multiple regulations over a long period are particularly challen-

ging. To obtain meaningful results, the specific characteristics of

the different capacity mechanisms adopted must be accurately

modelled. For the French mechanism, this would notably require

factoring in the impact of the active capacity need management

promoted through the mechanism’s decentralised architecture,

as this could reduce the overall cost of covering the shortfall risk

compared with a situation where capacity adequacy is managed

passively. Transaction costs would also have to be evaluated.

Different descriptions of the functioning of capacity mecha-

nisms have been presented since European authorities began

to express concerns about the development of national mecha-

nisms. Some of these descriptions do not seem compelling:

either the mechanisms are described in summary form, in which

case the results reflect the crude nature of the initial assump-

tions, or they are modelled in detail but using simulations that

only show costs in a static manner, without considering how

these costs will influence the behaviour of those that bear them.

The sections below illustrate this dichotomy:

> Careful analysis of reports, such as the one appended to the

summary of the public consultation organised by the Euro-

pean Commission on the internal market and published in

June 2013, shows that trying to simulate the impact of the

introduction of mechanisms in France and Germany can result

in an oversimplified description of the capacity mechanism,

such that the mechanism simulated bears no resemblance to

the one adopted, making the results incorrect (§ 8.2);

> Simulations aiming to evaluate the financial impact of a capa-

city mechanism for consumers, with “all other things being

equal”, are then presented (§  8.3): however, the results only

represent the “first-round” impacts, and do not include a dyna-

mic analysis of the longer-term effects on the power system

(location of investments, trends in market prices, etc.).

8.2 Limitations of existing analyses of how the capacity mechanism functions in an interconnected market

numerous Member States. Along with this Communication, it

launched a public consultation on the internal energy market,

generation adequacy and capacity mechanisms.

The European Commission took the 132 consultation res-

ponses submitted into account in preparing its Communication

on making the most of public intervention. It published the res-

ponses to the public consultation along with a report entitled

8.2.1 Analysis of the report accompanying the European Commission guidelines on public interventions

8.2.1.1 The report and its conclusions

In its Communication of 15  November 2012 on making

the internal market work, the European Commission voiced

concerns about the introduction of capacity mechanisms in

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CAPACITY MECHANISM IMPACT ASSESSMENTS / 8

207[EC, 2012a]

208The report was prepared by Thema Consulting Group, E3M-Lab and COWI.

209Executive summary of the report: The empirical analysis shows that there is generally no urgent need for capacity mechanisms in Europe. Individual (asymmetric) capacity mechanisms of all designs are prone to distort cross-border trade in two main ways:- By causing over-capacity: Regulators are likely to overestimate the necessary domestic capacity reserve margin and to underestimate the contribution from cross-border trade.- By distorting allocation of investments: Investments are likely to shift to markets with CRM, thereby increasing total costs and distorting cross-border trade.

210Section 7.6 of the Thema report, “Capacity Mechanisms in Individual Markets within the IEM”: Asymmetric capacity mechanisms in the IEM imply that capacity remuneration in addition to energy-only market revenues are only applied in some system control areas and only remunerate plants located in this area. It is assumed that other (usually adjacent) system control areas operate as energy-only markets. Assuming that the asymmetry is taken into account by investors, generation capacity investments by country differ from symmetric energy-only market cases.

211OPTIMATE is a market architecture simulator designed as part of a European R&D programme.

“Capacity Mechanisms in Individual Markets within the IEM”207,

a document also used in drafting the Communication on public

intervention. This report208 analyses the consequences of the

introduction of capacity mechanisms in Europe.

On the whole, the findings of the report209 are unfavourable to

the adoption of capacity mechanisms in Europe. They notably

warn of the risk of market distortion if there is no coordination

on mechanism implementation.

However, the report does not conclude that the energy-only

market alone can stimulate investments in electricity:

It is difficult on an empirical basis to determine whether the

energy-only market design of the target model will yield

adequate investment signals. Moreover, the academic lite-

rature is inconclusive too. Whereas some hold that energy-

only markets are fundamentally flawed and that there is a

need for permanent capacity remuneration mechanisms

(CRM), others argue that the need for such mechanisms

is mainly linked to temporary market interventions and

uncertainties as [Climate policy, Market development, Mar-

ket regulations and Market design, Technology and costs &

Economic environment].

[…]

Still, it cannot be ruled out that capacity mechanisms may

be necessary to ensure sufficient peak and back-up capacity

in the future low carbon European electricity system, or as a

transitory precaution in some individual member states in the

shorter term.

The main conclusion of the qualitative analysis is that there is

no immediate and general underlying need for capacity mecha-

nisms in Europe. The two key conclusions of the accompanying

quantitative analysis are:

> The architecture of the energy-only market may not suffice to

ensure the economic viability of at least a portion of capacities:

The model based analysis reveals that the economics of new

capacity, in particular in gas-fired open cycle and CCGT plants,

may be challenging.

> Non-coordinated introduction of capacity mechanisms could

have negative consequences for Europe as a whole:

Model simulations of individual CRM in France and Germany,

respectively, confirm that unilateral mechanisms distort

investments and trade and lead to higher sys-

tem costs. The impacts on investments differ

in the two cases due to differences in capa-

city mix and interconnectivity. Impacts are felt

throughout Europe and total costs increase in

both cases. Compared to the reference sce-

nario (which also exhibits adequate capacity),

EU generation costs are found to increase by

1.3-1.5%.

The latter conclusion is important: if it is valid, then it

could call into question the justification for a capa-

city mechanism in France. The first task must the-

refore be to examine the robustness and validity of

the approach presented in section 7.6 of the Com-

mission’s report, “Impact of asymmetric capacity

mechanisms”.

8.2.1.2 General analysis of methodology

The methodology underpinning the assessment

is based on a comparison of a reference situation,

with energy-only markets in place in all countries,

and an “asymmetric” situation where one only

country adopts a capacity mechanism210.

This methodology is useful for studying market

architectures, and is notably used for the OPTIMATE

project211. However, the consequences of each

choice must be properly evaluated for the compa-

rison to be meaningful. This was not done for the

study included in the “Capacity Mechanisms in Indi-

vidual Markets within the IEM” report:

The approach in this section is that the asymme-

tric capacity mechanism represents a distortion

of the optimal market configuration presented in

previous sections. This simulation assumes that

reserve and reliability criteria are met in all sys-

tem control areas, taking interconnections into

account. In other words, the LOLPs are below

the maximum accepted thresholds and there is

no reason for an individual control area to adopt

a unilateral capacity mechanism. The question

posed in this section is then what would be the

impacts if a distorting regulation which remunerates capaci-

ties unilaterally was adopted in one control area. The mode-

ling does not account for any direct benefits in terms of loss

of load probabilities.

182

In other words, it is assumed that the energy-only market archi-

tecture is perfect and ensures optimal investment develop-

ment212. The security of supply benefits a capacity mechanism

could provide are not taken into account, even though these

benefits are the raison d’être for the mechanisms213.

The methodology used in the study presented in the “Capacity

Mechanisms in Individual Markets within the IEM” report there-

fore introduces non-negligible bias in that:

> The reference situation is a perfect energy-only mar-

ket that guarantees adequacy. As the authors explain,

“there is no reason [in this simulation] to adopt a

capacity mechanism”. In sum, it is considered from

the outset that the introduction of a mechanism

purportedly serving no purpose can only detract

from an initial situation that is theoretically optimal;

> The potential benefits of capacity mechanisms

in terms of security of supply are not taken into

account. This is tantamount to conducting a cost-

benefit analysis without taking benefits into account.

Both of these biases are highly questionable: many

academic studies have shown that the energy-only

market does not produce optimal results (these stu-

dies are summarised in chapter 1), and that the exis-

tence of externalities makes it necessary to adopt

specific mechanisms to ensure security of supply.

Empirical observations also support the theory that

market failures and investment cycles do exist.

8.2.1.3 Analysis of simulation assumptions

and data

It is suggested that the study allows the adoption of

a capacity mechanism in France to be simulated.

However, the assumptions and data inputted to the

model describe a mechanism that is in fact radically

different from the French mechanism:

We assume that the capacity remuneration fee allows

open cycle gas plants to recover capital costs. We also

assume that the same fee applies to CCGT plants as well.

The level of this fee is 40k€/MW-year in both cases.

The study thus considers a capacity payment mecha-

nism that specifically rewards certain technologies at

a particularly high fee. In other words, the study simu-

lates the adoption of a mechanism that is diametrically

opposed to the one being introduced in France. The French mecha-

nism is based on a capacity market that covers all capacity (market-

wide) and is technologically neutral. The price is not set ahead of time

but rather by the market, at the point where the supply and demand

curves for certificates meet. These are fundamental differences and

they profoundly impact the effects of the capacity mechanism.

In sum, the results of the study the European Commission

published as a complement to the consultation on the internal

market do not apply to the French mechanism. At best, they

show, based on an extremely simplified model, that a selective

capacity payment mechanism planned without taking the secu-

rity of supply situation into consideration can result in massive

and subsidised excess capacity214. This is precisely the concern

that led public authorities in France to opt for a decentralised,

quantity-based mechanism (chapter 2). Moreover, in designing

the rules submitted for approval by the Minister and CRE (chap-

ter 3), RTE sought to prevent the mechanism from keeping

excess capacity in the market when more competitive resources

were still available to safeguard security of supply. As such, there

should be no bias in favour of overcapacity in the French system

since, with the capacity mechanism in place, the capacity price

should tend toward zero in situations of excess capacity215.

Lastly, the mechanism simulated in the study the European Commis-

sion financed only focuses on some technologies (combined-and

open-cycle gas turbines). It therefore introduces a distortion and

promotes the development of these technologies exclusively. The

French mechanism will treat all capacities equally through a techno-

logy-neutral certification process216, and will also take demand res-

ponse capacities into account, as illustrated in chapter 3.

The bottom line is that the mechanism simulated in the study,

based on hypotheses, includes biases that public authorities

expressly sought to avoid in France. This raises two problems:

> The fact that the simulations are presented as representations of

the French capacity mechanism could mislead readers, since the

mechanism simulated bears no resemblance whatsoever to the

French capacity market. The results can therefore not be used to

evaluate the efficiency of the French capacity mechanism;

> The results are of limited validity in practice since only one type

of mechanism is simulated with only one capacity remuneration

fee. The fact that they are presented in a very general form217

automatically biases the reading and interpretation of the results.

8.2.1.4 Analysis of study results

The study results are analysed qualitatively, which allows the ori-

gin of the additional costs identified to be undertsood:

212Section 7.6 of the Thema report, “Capacity Mechanisms in Individual Markets within the IEM”: We assume that investment develops in an optimal way under reference conditions (cf. 7.1.4) so as to ensure capacity adequacy (captured through system reserve margin thresholds and the ramping constraints). This development of investment constitutes the benchmark case or, as referred to in the text that follows, the energy-only markets case.

213Section 7.6 of the Thema report, “Capacity Mechanisms in Individual Markets within the IEM”: We do not model capacity adequacy failure cases. […] The possible benefits of [a capacity mechanism] in terms of avoiding damages from unforeseen power supply failures are not accounted for in our modelling.

214The European Commission explicitly recommends against this specific characteristic in its guidance for state intervention in electricity: “Does the chosen mechanism ensure that identified adequacy gap will be filled while avoiding risks of overcompensation (unlikely with payments payments)?”

215In accordance with the recommendations in the European Commission guidance on state intervention: “Capacity mechanisms should be designed to deliver a price of zero when there is sufficient capacity available.”

183

CAPACITY MECHANISM IMPACT ASSESSMENTS / 8

As expected, the increased incentives to invest in peak load

devices in France leads to an increase in the overall invest-

ments in France, while the opposite effect is observed in

neighbouring, interconnected countries. More specifically,

up to 2030, the model suggests that, relative to when France

operates an energy-only market, investment in France will

increase by 21.7 GW, while investments decrease by 15.9 GW

in Germany, 3.6  GW in Belgium and 2.1  GW in the Nether-

lands. The changes mainly concern open cycle gas plants

and to some extent CCGT plants (Table 20). The generation

mix in France is considerably altered, as capacity remunera-

tion attracts much more investments in open cycle plants

than projected in the reference case. The share of open-cycle

plants in the overall non-RES projected investments is 40%,

more than double than in the reference case. The correspon-

ding share of the base-load investments falls to 50% from

70% in the reference case.

The additional costs identified stem directly from the errors and

approximations mentioned in the previous section:

> The total quantity of capacity is distorted: the simulations point to

overcapacity in France and under-capacity in the other countries.

This is a direct result of the “blindness” of the mechanism simula-

ted, which involves unconditional capacity payments;

> The generation mix is distorted: the simulations point to ove-

rinvestment in peak generation capacities and an underre-

presentation of base-load capacities. These effects are direct

results of the fact that the mechanism simulated targets only

specific technologies (gas-fired power plants).

8.2.2 Factors minimising the French mechanism’s impact on neighbouring countries

It is all the more important to carefully examine the

reality of the market architecture adopted when

modelling its impact on neighbouring countries

given that the interaction between energy markets

was a constant concern while the French mecha-

nism was being designed.

At the very outset of the mechanism design process,

it was perfectly clear that the principles applied to

the management of cross-border interconnections

in Europe made it impossible to duplicate the sys-

tems adopted in the United States, and the progres-

sive coupling of European markets made this issue

all the more pressing218. With this in mind, priority

was given to ensuring that the capacity mechanism

would not interfere with the organisation of the

internal energy market:

The introduction of a capacity mechanism

should not jeopardise the benefits of efficient

market functioning […]. This is why it is important

that the mechanism does not interfere with the

operation of market rules219.

Under the mechanism, operators’ commitments

to make capacity available during peak periods do

not limit their generation output (which will still be

determined by the functioning of energy markets)

or the destination of that output (still determined

by the rules in effect, and notably by market cou-

pling220). In other words, participation in the French

capacity mechanism does not involve any obliga-

tion in terms of generation supply on energy mar-

kets or equivalent restrictions on exports: a capacity

that is dispatched within the framework of the mar-

ket, even if an export contract is in effect, is consi-

dered to be available. Nor does the supplier that

holds the certificates associated with the capacity

have rights to the energy produced: energy cannot

be reserved in this system. Lastly, the adoption of

the capacity mechanism has no consequences in

terms of regulating energy prices, for instance on

the setting of price caps/floors.

216In accordance with the recommendations in the European Commission guidance on state intervention, under the heading “technological neutrality”: “Base restrictions on participation in a mechanism to ensure generation adequacy on the technical performance required to fill the identified adequacy gap and not on predefined technology types.”

217Taken from the Executive Summary of the “Capacity Mechanisms in Individual Markets within the IEM” report: “Model simulations of individual CRM in France and Germany, respectively, confirm that unilateral mechanisms distort investments and trade and lead to higher system costs. The impacts on investments differ in the two cases due to differences in capacity mix and interconnectivity. Impacts are felt throughout Europe and total costs increase in both cases. Compared to the reference scenario (which also exhibits adequate capacity), EU generation costs are found to increase by 1.3-1.5%.”

218[Veyrenc & Bhavaraju, 2008]

219[EC, 2013a]

220As was shown during the 2011 consultation, energy market coupling eliminates the concept of energy destination.

The “Capacity Mechanisms in Individual Markets within the IEM” report published with the results of the public consultation of 15 November 2012 on the internal energy market includes quantita-tive analyses of the effects of the implementa-tion of the French capacity mechanism.

An analysis of the methodology, assumptions and data used in the study and its results shows that the mechanism simulated bears no resem-blance to the one adopted in France. The conclu-sions of this report must be viewed with caution. It should also be noted that some principles laid down by the European Commission in its Com-munication on making the most of public inter-vention, and the Staff Working Document this report accompanies, are not upheld with the mechanism simulated. It would have been use-ful to have a thorough study of these aspects, despite the complexity involved.

184

the scope of validity of the results presented in the pages that

follow.

The impact assessments presented analyse how the cost of the

capacity obligation is distributed between different consumer

categories. They combine the different hypotheses in a number

of scenarios to identify the configurations that are the most or

least favourable to individual stakeholder categories (§ 8.3.2).

A numerical estimate is also provided of the indirect effect on

final consumers through the contribution to the public service

of electricity (CSPE) they pay. Indeed, facilities benefiting from

purchase obligations effectively participate in the capacity mar-

ket since they are awarded capacity certificates; in accordance

In response to stakeholders’ request to have a comprehensive

view of the mechanism’s effects, in September 2013, RTE pro-

vided some data on the financial impact the mechanism would

have on certain categories of consumers. These data have since

been expanded and are presented below. They show the first-

round effects of the implementation, on an all other things being

equal basis, and illustrate the immediate impact the mechanism

will have, not taking into account any effects implementation

will have on stakeholders’ behaviours or strategies, something a

dynamic analysis can show.

The methodological framework and hypotheses

used in the impact assessments are outlined below

(§  8.3.1). This information is crucial to establishing

These principles imply that the energy market will be com-

pletely decoupled from the capacity mechanism in the short

term. They will prevent the mechanism from having any direct

short-term effects on energy prices, since the full separation of

capacity and energy as products is guaranteed, meaning Euro-

pean energy markets will continue to play the same role. These

options make the system very different from that in effect in the

United States, where the revenue earned by a generation unit in

the energy and capacity markets can in some cases be offset.

Once the mechanism is in place, it will be necessary to verify that

decoupling is truly a source of economic efficiency and that is

does not translate into undue rents during peak periods.

On the other hand, over the long term, the mechanism could

indirectly influence prices. As the Agency for the Cooperation of

Energy Regulators notes in its report on capacity mechanisms,

direct effects are not the only impact to consider:

Secondly, [Capacity Mechanisms] may influence investment

decisions (investment in plants and their locations), with

potential impacts in the long term […]221.

It would not be desirable for the capacity mechanism to have no

influence whatsoever on investment decisions, except if there was

no capacity need at all. The idea, rather, is to ensure that the mecha-

nism’s long-term impacts are strictly proportionate to its objectives,

in which case there is no distortion since the different mecha-

nisms allow the objectives set for them to be met. The architecture

adopted for the French mechanism ensures that the market price

of capacity certificates will tend toward zero if no capacity is needed.

ACER’s recommendations nonetheless stress the incomplete-

ness of the studies currently available in terms of the long-term

impact the coexistence of different national regulations will have

on security of supply. More thorough studies would be complex

and cannot be conducted before the parameters of the mecha-

nism are defined. It is proposed that such studies be conducted

as part of the effort to support the mechanism’s rollout, applying

the provisions proposed in the rules in application of the decree.

8.3 Detailed analysis of short-term effects

221[ACER, 2013]

The French capacity mechanism was designed in such a way as to minimise its impact on energy markets:

> In the short term, energy and capacity “products” will be completely independent and there will be no interference;

> In the long term, the capacity mechanism will influence investment decisions proportionately to security of supply targets: the resulting impact on energy prices should be indirect and small.

Additional studies are required to quantify this effect. To be conclusive, they must factor in all parameters set by public authorities. These stud-ies will be conducted within the framework of the existing provisions of the decree and those adopted in the rules when the capacity mecha-nism is in place.

185

CAPACITY MECHANISM IMPACT ASSESSMENTS / 8

with the provisions of the law, the value of these certificates is

returned to final consumers via a reduction in public service

charges through the CSPE (§ 8.3.3).

8.3.1 Hypotheses

Various factors must be taken into account in analysing the eco-

nomic impact of the mechanism. Six explanatory parameters

were identified and tested in the simulations described below:

> The value of the security factor, which notably changes depen-

ding on the recognition of the contribution of foreign capacity

(see chapter 9 for more details);

> The capacity price, which allows different configurations to be

tested with regard to the security of supply outlook;

> The temperature sensitivity of consumers, which varies widely

between consumers and results in a very uneven distribution

of the national obligation, meaning that economic impacts are

highly segmented;

> The consumer’s ability to reduce load during peak periods,

which is a means for consumers to directly manage the “capa-

city risk” and influences the impact of the mechanism depen-

ding on consumers’ flexibility;

> The regulatory framework in the wholesale market, which

affects the initial distribution of capacity certificates between

market players. The procedure adopted for the transfer of

capacity certificates associated with ARENH generation (see

chapter 7) will thus be all-important, since it will have a deci-

sive influence on the competitive structure of the future

capacity market (and, in practice, it will also do a great deal to

balance players’ positions);

> The regulatory framework in the retail market, which affects

how costs are passed on to consumers, notably depending on

the rates suppliers offer them. A distinction must therefore be

drawn between large consumers whose rates depend on mar-

ket prices and smaller consumers that can remain on regula-

ted tariffs between now and when the capacity mechanism

takes effect.

8.3.1.1 Security factor

The value of the security factor depends on two parameters:

> How the contribution to security of supply in France of capa-

cities located in other countries is modelled: this contribution

is accounted for implicitly, through a reduction in the security

factor; the higher the contribution of foreign capacities, the

greater the reduction in the security factor;

> The technical choices made in the rules, are notably between

(i) making the reference extreme temperature the main contin-

gency considered or on the contrary pooling all contingencies

within the security factor, or (ii) stabilising the parameters for

calculating the obligation or normalising the amount of certi-

ficates allocated to certain capacities and pooling the related

“imperfections” through the security factor.

As discussed in § 4.4, RTE proposes that the security factor be

set at 0.93 for the first two delivery years.

A different approach could have been taken in accounting for

the contribution of interconnections. If public authorities decide

not to take the contribution of interconnections into account, or

to account for it while also increasing the three-hour coverage

threshold (considering the three-hour criterion without taking

interconnections into account would result in a higher level of

effective coverage), the value of the security factor could be 1.

The two hypotheses tested below thus correspond to a security

factor of 0.93 or 1.

8.3.1.2 Capacity price

Assessing the economic impacts of the mechanism requires

using a hypothesis of the average capacity price that will result

from transactions in the market. Of course this price depends on

the projected state of the power system, but also on the para-

meters set in the rules, such as the value of the security factor

and the reference extreme temperature. Insofar as the “security

factor” variable is tested separately, testing the “capacity price”

variable means examining the impact of the “reference extreme

temperature” parameter.

The capacity certificate price could in theory move between 0

and the administered price used for the imbalance settlement,

which RTE proposes to define as the annualised cost of develo-

ping a peak generation plant (combustion turbine), of €60k/MW

for a given delivery year. The simulation could therefore test the

range [0; €60k/MW]

However, given the supply-demand balance outlook presented

in chapter 1, which predicts a situation that requires vigilance

but does not imply a definite shortage, it is proposed that a nar-

rower price range be considered. A capacity price of €30k/MW/

year for all capacities corresponds in all likelihood to a high value

for the first delivery years.

The two hypotheses tested below thus correspond to prices of

€10k/MW/year and €30k/MW/year. A reference situation with

a capacity price of zero will also be considered.

186

8.3.1.3 Temperature sensitivity

The data presented in chapter 4 allow a qualitative assessment

of the impact of the formula used to determine the obligation.

Because the formula selected is based on the consumption gra-

dient, the lion’s share of the national obligation will be allocated

to temperature sensitive consumers. This is logical since they

are responsible for peak power demand and thus the need for

peak generation capacity. On the other hand, non-temperature

sensitive consumers should not be affected by the capacity

mechanism; the gradient is even set at 0 for some of them.

In the simulations presented here, differences in consumers’

temperature sensitivity are considered through “idealised”

hypothetical cases (100% base-line consumption) and concrete

examples based on actual load curves.

The configurations tested thus correspond to a gradation

between the consumer that is not temperature sensitive at all

(industrial user for instance) and a residential consu-

mer with electric heating.

8.3.1.4 Consumer’s ability to reduce load at

peak times

The principle underlying the mechanism adopted in

France is that any consumer or supplier should be

able to manage the risk the obligation represents

for it by leveraging its demand response potential

during peak periods.

This means that the capacity mechanism will have a

very different impact on a highly temperature sen-

sitive consumer that absolutely cannot adjust its

consumption and a consumer that can reduce load

during peak times. A consumer with a very low obli-

gation (industrial user for instance) can take advan-

tage of this flexibility to generate a net gain with the

mechanism.

The simulations illustrate this by considering two

hypotheses: a consumer that never reduces load

and one that reduces its peak consumption by half

on all PP1 days.

8.3.1.5 Specific mechanism regulating the

wholesale market: transfers of ARENH-related

capacity certificates

Another significant variable is how capacity cer-

tificates associated with the ARENH mechanism

discussed in § 7.3 affect the analysis of competitive conditions

in the capacity certificate market.

ARENH is a regulatory mechanism that was instituted by the

NOME Act in 2010 to facilitate the deregulation of the French

supply market while also allowing consumers to benefit directly

from the competitiveness of historical nuclear electricity. The

law provides that each supplier shall have Regulated Access to

Historical Nuclear Electricity (ARENH) under the same econo-

mic conditions as the incumbent operator222.

As a result, alternative suppliers:

> Pay a price that factors in the costs associated with histori-

cal nuclear generation capacity: the ARENH purchase price is

representative of the economic conditions under which histo-

rical nuclear electricity is generated;

> Benefit from all advantages associated with historical nuclear

electricity in terms of energy but also capacity certificates.

In application of this second principle, current regulations sti-

pulate that alternative suppliers will receive the capacity cer-

tificates associated with energy sourced through the ARENH

mechanism223. This is a crucial factor in evaluating how the

mechanism will function; the consequences in terms of com-

petition were discussed in chapter 7. In practice, alternative sup-

pliers with ARENH rights will not be “net buyers” on the market,

but rather will be in a situation comparable (at least in part) to

that of players with upstream-downstream integration.

The capacity value associated with ARENH is an important com-

ponent of the impact assessment. However, whereas RTE is res-

ponsible for proposing a security factor value, CRE is charged

with proposing a method for calculating the amount of capacity

certificates to be delivered with ARENH rights224, and it has orga-

nised a consultation in recent months to consult market stake-

holders on this subject. The fact that the results of this process

are not yet known makes it necessary to formulate hypotheses

about the coefficient that will be applied to convert 1  MW of

ARENH electricity delivered into a number of capacity certifi-

cates. Needless to say, these hypotheses are without prejudice

to the choice that will ultimately be made by CRE.

In conducting the evaluations below, RTE considered two

hypotheses, corresponding to the two lines of reasoning

promoted by stakeholders during the consultation. These

hypotheses were presented in September 2013, and were not

challenged in the responses to the public consultation orga-

nised by RTE:

222As stated in L. 336-1 of the Energy Code: “To ensure that consumers are free to choose their electricity supplier, while also promoting the attractiveness of the country and allowing all consumers to benefit from the competitive pricing of nuclear power generated in France, it will be possible, during a transitional period defined in article L. 336-2, for all operators supplying final consumers in continental metropolitan France, or system operators for their losses, to have regulated and limited access to historical nuclear electricity from the nuclear plants mentioned in article L. 336-2 on economic terms equivalent to the conditions for Electricité de France resulting from the use of the nuclear plants mentioned in the same article L. 336-2.”

223Decree 2011-466 of 28 April 2011 setting out the rules governing access to historical nuclear electricity stipulates that “the product transferred includes the generation capacity certificate, as defined in article 4-2 of the aforementioned law of 10 February 2000”.

187

CAPACITY MECHANISM IMPACT ASSESSMENTS / 8

> The first involves allocating one MW of capacity guarantee for

each MW of ARENH electricity delivered;

> The second involves using a different conversion key to try

to create a level playing field for alternative suppliers and EDF.

First hypothesis

ARENH is defined as a “flat” product and alternative suppliers’

allocation rights are based on their customers’ consumption

during the reference periods defined in the regulations. By this

same logic, the transfer involves allocating one capacity certifi-

cate for each MW of ARENH electricity delivered.

Second hypothesis

Transfers based on a conversion rate of more than 1 suggested

during the consultation apply a different logic to the allocation

of capacity certificates. It involves calculating the distribution of

certificates in such a way as to ensure that each supplier is in an

“equivalent economic position” to EDF with regard to historical

nuclear generation capacity. This calculation can be based on

an estimation of the number of capacity certificates “contained”

in each MWh of nuclear electricity produced:

> It is assumed that the certification of the historical nuclear

power plants will result in the issuance of 55 GW of capacity

certificates (estimated applying the certification methods pro-

posed225 to historical availability data in recent winters, based

on RTE’s assessments);

> This amount is then compared to annual nuclear electri-

city generation (416  TWh on average in the past ten years):

each MWh of nuclear electricity thus “contains” an average

0.132 kW of certificates;

> The conversion key thus works out to 1.16 (1 MW of ARENH

generated produces 8760 x 0.132 kW = 1.16 MW of capacity

certificates in a year).

It may seem surprising that the ratio between certificates in

MW and ARENH generation in MW is greater than 1. This result

actually reflects the fact that the nuclear power plants are

more available in the winter, and thus during the PP2 periods:

the amount of certificates allocated to nuclear power plants is

higher than the average power delivered in a year (55  GW in

winter, compared with average output of 48 GW over the year).

In other words, the second hypothesis involves transferring to

suppliers, through ARENH, the value associated with the modu-

lation of generation. To be thorough, this hypothesis should

be qualified: the cost of imbalance settlements resulting from

the certification of nuclear capacity should also be passed on

to suppliers if they are to be on equal economic footing with

EDF. It is assumed that this cost will be minimal: nonetheless, the

value has been rounded down from 1.16 to 1.15 by

default for the purposes of the assessments.

As such, the conversion key values applied in the

simulation to translate MW of ARENH capacity into

capacity certificates are 1 and 1.15, respectively.

8.3.1.6 Regulatory framework in retail

market

The regulatory framework governing the retail mar-

ket affects how costs are passed through to consu-

mers, notably depending on the type of rates sup-

pliers are likely to offer them.

Under current legislation, regulated tariffs, to

which large consumers226 can still subscribe, will

be phased out on 1  January 2016, before the first

capacity mechanism delivery year begins. From the

first delivery year on, large consumers will only have

access to market rates, which will factor in the bene-

fits of ARENH generation if it is more competitive

than the market price.

On the other hand, small consumers (subscribed

power of no more than 36 kVA) will be able, as of the

first deliver year, to choose between the regulated

tariffs offered by the incumbent operator and local

distribution companies or the market rates offered

by alternative suppliers. The continued availabi-

lity of regulated tariffs will impact how the market

functions. Indeed, the law establishes a principle

of reversibility allowing small consumers to switch

from regulated tariffs to market rates and vice versa.

From a competition standpoint, regulated tariffs act

as an automatic price cap on the rates offered by all

suppliers in the French electricity market: it can be

considered, in this segment, that the regulated tariff

is the reference price for the retail market.

In other words, the capacity mechanism will not

have the same impact on different categories of

consumers:

> For large consumers, it is the impact on market rates (deter-

mined based on the ARENH price plus a market supplement)

that must be analysed;

> For small consumers, the goal is to assess the impact on cur-

rent supply prices in the segment, assuming that they will be

aligned with the regulated tariff at this timescale227.

224Decree 2012-1405 of 14 December 2012 relative to the contribution of suppliers to security of electricity supply and to the creation of a capacity obligation mechanism in the electricity sector states that it is CRE’s responsibility to propose the method for calculating the amount of capacity certificates to be delivered with ARENH electricity (the method used to calculate this amount of capacity certificates, along with the transfer terms and timeframe, are defined in an order by the Energy Minister based on a proposal by the Energy Regulatory Commission”). Article 337-14 affirms: “To ensure fair remuneration for Electricité de France, the price, which will be reassessed every year, shall be representative of the economic conditions under which the nuclear power plants mentioned in Article L. 336-2 generate electricity over the duration of the mechanism defined in Article L. 336-8.”

225See section 5.1.2 of this report.

226Large consumers are defined in accordance with the terminology used in decree 2011-466 of 28 April 2011 setting forth the rules for regulated access to historical nuclear electricity, i.e. sites subscribing to power of more than 36 kVA, by contrast to small consumers.

227This is a simulation hypotheses that obviously does not imply that all rates will be effectively aligned.

188

The simulations presented below therefore draw a distinction

between the impact for large (industrial) consumers and small (resi-

dential and tertiary) consumers. Insofar as the tariff framework appli-

cable to the latter after 1 January 2016 will be adjusted by the Govern-

ment and Energy Regulatory Commission between now and then,

the simulations involving large consumers are more detailed.

8.3.1.7 Results

To be thorough, the impact assessment must vary these six

explanatory factors. It is not easy to provide an aggregate result

for something this complex: the method applied involves com-

bining certain hypotheses to produce different scenarios.

This scenario-based approach notably allows correlations

between different coefficients to be taken into account. For ins-

tance, selecting a low security factor will, all other things being

equal, result in a lower market price. The studies below therefore

do not simultaneously test a hypothesis involving a low security

factor together with a high capacity price.

Figure 79 – Overview of explanatory factors to be taken into account in the impact assessment

Explanatory factor Hypotheses applied in the scenario-based approach Determination

Security factor

0.93 Value proposed by RTE in the rules

Set in the RTE rules

1Higher level of security of supply chosen for France

(No taking account of the contribution of interconnections or increase in the criterion)

Capacity price

€0k/MW/year Floor price scenario

Dependent on functioning of capacity market €10k/MW/year Median scenario tested

€30k/MW/year High scenario tested

Temperature sensitivity

Industrial consumer

Non-temperature sensitive Consumer

Set in the RTE rules

Residential consumer

Consumer using electric heating

Consumer's ability to reduce load

Consumer that never reduces load

Dependent on consumers

Consumer that reduces peak power demand by half throughout PP1

Transfers of ARENH-related certificates

1 MW of ARENH = 1 MW of certificates

Same approach as for allocation of rights to alternative suppliers

Set by Minister and CRE

1 MW of ARENH = 1.15 MW of certificates

Alternative approach that involves estimating the number of capacity certificates “contained” in each MWh of nuclear electricity produced

Regulatory framework in retail market

Large consumerImpact on market rates

(based on ARENH price plus a market supplement)

Set by Minister and CRE

Small consumerImpact on market rates linked to regulated tariffs (it is assumed

they will align with regulated tariffs in effect at this timescale)

189

CAPACITY MECHANISM IMPACT ASSESSMENTS / 8

8.3.2 Quantitative assessment of cost to consumers

The outcomes of the simulations presented here depend on the

hypotheses above. They exclude taxes and network costs.

As with the discussion of competition-related factors in chap-

ter 7, the ARENH effects are central to the assessment. Cal-

culated based on the methodology that will apply in 2015 to

a virtual consumer with a consumption profile similar to the

national load curve, ARENH rights will represent, by RTE’s esti-

mates, about 78% of its energy needs228. In power terms, his-

torical nuclear electricity should account for just over half of

its capacity certificate needs. Assuming a total capacity certifi-

cate requirement of 92 GW (estimated applying the proposed

methods for certifying the total capacity needed in 2016-

2017), and that certification of historical nuclear generation

capacity totals 55  GW (estimated applying the proposed cer-

tification methods to availability data for recent winters), then

historical nuclear electricity will represent 60% of the overall

capacity need.

This ratio varies considerably depending on the type of

consumption. For a small consumer with subscribing to a peak/

off-peak tariff (which most consumers with electric heating do),

ARENH electricity could cover about two-thirds of its energy

consumption229, but less than half of its capacity obligation.

Conversely, for an industrial consumer with a consumption

profile that is not very seasonal, ARENH electricity could cover

almost all of its energy and capacity certificate needs. Impacts

thus vary depending on the consumer category.

8.3.2.1 Large consumers

By the time the capacity mechanism is in effect, all large

consumers will be paying market rates, as the regulated tariffs

still available to consumers that never exercised their right to

switch since the market was deregulated will be phased out on

31 December 2015.

Suppliers base their market rates on wholesale market prices.

If ARENH electricity is still a competitive source for alternative

suppliers when the mechanism comes into effect, market rates

should align with ARENH supply costs, tacking on a “market sup-

plement”. Otherwise, the rates offered to large suppliers will be

based entirely on the wholesale market price.

Bearing this in mind, the capacity mechanism’s impact on each

consumer in this segment should be a direct reflection of the

capacity obligation it creates for its supplier. This

amount can nonetheless be adjusted to reflect

the capacity certificates transferred to alternative

suppliers through the ARENH and priced through

the capacity market. Assessing the mechanism’s

impact on these consumers therefore involves

weighing the capacity obligation they create for

their supplier against the certificates these same

suppliers receive in relation to the ARENH, assu-

ming that suppliers will indeed pass on to their

customers the capacity value included in ARENH

rights thanks to effective competition in the elec-

tricity supply market.

Three cases are analysed below: (1) a virtual consu-

mer consuming base-load electricity exclusively,

(2) a very large consumer with the “average” pro-

file typifying all consumers connected to the public

transmission system, and (3) a typical remotely read

large consumer connected to the public transmis-

sion system.

All three analyses were conducted bearing in mind that the

mechanism parameters were subject to further modifications. In

all three cases, the delivery year is staggered with a winter period

in the middle in order to obtain, within the time allotted for the

consultation and the drafting of the rules, an initial estimate of

the capacity mechanism’s consequences. The fact that a calen-

dar year is adopted in the rules only has a marginal impact on

outcomes, as explained in chapter 4.

8.3.2.1.1  Virtual consumer consuming base-load 

generation exclusively 

The ideal configuration for this consumer (excluding demand

response) is a low capacity price, the security factor proposed

by RTE and a conversion key greater than 1 (i.e. the second

hypothesis for this parameter).

Pursuant to the order of 17 May 2011 relative to the calculation of

rights to regulated access to historical nuclear electricity, a consu-

mer with steady power consumption creates, for its supplier, an

ARENH right corresponding to 96.4% of the energy consumed.

If 1.15  MW of capacity certificates are transferred for every

MW of ARENH electricity delivered, then the certificates obtai-

ned through ARENH represent 110.6% of power consumed

(calculated by multiplying the ARENH right by the capacity

certificate).

228Throughout the assessment, it is assumed that the maximum total ARENH electricity that can be delivered, which the law caps at 100 TWh, is not reached. If the cap is reached, then regulations stipulate that the ARENH rights allocated to each supplier shall be reduced in such a way that the amount is divided between suppliers requesting ARENH.

229CRE’s 2011-2012 report on the functioning of retail electricity and natural gas markets in France, published in January 2013, mentions (p. 56) that the ARENH rights calculated for the off-peak/peak hour profile is 64.1%.

190

In terms of the obligation, assuming a security factor of 0.93, the

obligation represents 93% of power consumption. In this case, it

appears that ARENH electricity goes beyond covering the consu-

mer’s need and results in a surplus of certifi cates, with ARENH

covering 119% of the obligation. Assuming a capacity price of

€10k/MW, the net gain for the consumer will be €0.2/MWh.

A site with a “fl at” consumption profi le and capable of reducing

its consumption by half during peak periods can also transfer

the corresponding certifi cates through the market, for a gain of

€0.6/MWh (assumed capacity price of €10k/MW). Added to the

€0.2/MWh mentioned above, this consumer’s net gain will be

€0.8/MWh.

The tables below show outcomes using diff erent hypotheses about

the capacity price, the security factor and ARENH certifi cates.

Now, if it is assumed that the security factor is determined with-

out taking into account the contribution of interconnections

and thus set at 1 (instead of 0.93), that each MW of ARENH

Figure 80 – Case of virtual consumer consuming base-load generation exclusively

0.8

0.85

0.9

0.95

1

1.05

1.1

1.15

01/0701/08

01/0901/10

01/1101/12

01/0101/02

01/0301/04

01/0501/06

* Peak consumption reduced by half

WITHOUT DEMAND RESPONSE

€/MWh1 MW of ARENH >1 MW of certifi cate

1 MW of ARENH >1.15 MW of certifi cate

C = 0.93 0.0 -0.2

C = 1 0.0 -0.1

WITH DEMAND RESPONSE*

€/MWh1 MW of ARENH >1 MW of certifi cate

1 MW of ARENH >1.15 MW of certifi cate

C = 0.93 -0.6 -0.8

C = 1 -0.6 -0.7

Capacityprice:€10k

WITHOUT DEMAND RESPONSE

€/MWh1 MW of ARENH >1 MW of certifi cate

1 MW of ARENH >1.15 MW of certifi cate

C = 0.93 -0.1 -0.6

C = 1 0.1 -0.4

WITH DEMAND RESPONSE*

€/MWh1 MW of ARENH >1 MW of certifi cate

1 MW of ARENH >1.15 MW of certifi cate

C = 0.93 -1.8 -2.3

C = 1 -1.6 -2.1

Capacityprice:€30k

Outcome with an alternative set of hypotheses

  Constant profi le

 Obligation with security factor of 0.93

 Obligation with security factor of 1

 Related capacity certifi cates transferred under ARENH (hypothesis: 1/1)

 Related capacity certifi cates transferred under ARENH (hypothesis: 1/1.15)

The tables below show outcomes using diff erent hypotheses about the capacity price, the security factor and ARENH certifi cates.

191

CAPACITY MECHANISM IMPACT ASSESSMENTS / 8

electricity produced translates into 1 MW of capacity certificates

(instead of 1.15), and that the market capacity price is €30k/MW,

the impact on the consumer’s bill becomes very slightly posi-

tive230 (+€0.1/MWh).

Taking flexibility into account has a substantial impact on the

outcome: if the consumer can reduce its consumption by half at

peak times, its gain will be €1.7/MWh (assumed capacity price of

€30k/MW). The net balance is positive for the consumer, which

will save €1.6/MWh.

8.3.2.1.2  Very large consumer with the “average” 

profile typifying consumers connected to the public 

transmission system 

The results above can be refined a first time by inputting the ave-

rage consumption profile of customers connected to the public

transmission system in the winter of 2011-2012231 rather than

assuming base-load consumption exclusively. This

configuration is a fair description of the consump-

tion profiles of most electro-intensive industrial users

connected to the transmission system.

The capacity obligation is calculated for the

100 hours of highest consumption, included in the

PP1 eligibility time slot [07:00; 15:00[ then [18:00;

20:00[, defined in accordance with the rules, norma-

lising the temperature gradient to 0 for the reasons explained in

chapter 4. ARENH rights are calculated applying the rules appli-

cable in 2015, based on a series that combines the first half of

2012 and the second half of 2011.

ARENH covers 105% of the obligation (conversion coefficient:

1.15). Assuming a capacity price of €10k/MW, the consumers in

question will see a net gain of €0.1/MWh.

Figure 81 – Case of large consumer with an “average” profile

0

0.2

0.4

0.6

0.8

1

1.2

1.4

01/07

01/08

01/09

01/10

01/11

01/12

01/01

01/02

01/03

01/04

01/05

01/06

Profile extraction PTS

Obligation with security factor of 0.93

Obligation with security factor of 1

Related capacity certificates transferred under ARENH (hypothesis: 1/1)

Related capacity certificates transferred under ARENH (hypothesis: 1/1,15)

A site with this kind of consumption profile and capable of redu-

cing its consumption by half at peak times can also transfer the

corresponding certificates through the market. This results in a

gain of €0.7/MWh (assumed capacity price of €10k/MW). Added

to the €0.1/MWh mentioned above, this consumer’s net gain

will be €0.8/MWh.

230In this case, ARENH covers 96.4% of the obligation.

231The data considered have not been adjusted for NEBs.

232ARENH covers in this case 85% of the obligation.

Now, if it is assumed that the security factor is determined without

taking into account the contribution of interconnections and thus

set at 1 (instead of 0.93), that each MW of ARENH electricity pro-

duced translates into 1  MW of capacity certificates (instead of

1.15), and that the market capacity price is €30k/MW, the impact

on the consumer’s bill will be an additional cost of €0.6/MWh232.

192

Here again, taking flexibility into account has a substantial impact

on the outcome: if the consumer can reduce its consumption

by half at peak times, its gain will be €2/MWh (assumed capacity

price of €30k/MW). The net balance is positive for the consumer,

which will save €1.4/MWh.

8.3.2.1.3  Typical large consumer (TSO or DSO) 

A third variant can be introduced to estimate the impact on the

energy bills of standard industrial consumers representative of

alternative suppliers’ portfolios. The simulation is conducted by

aggregating the remotely-read load curves of the balance res-

ponsible entities of these suppliers. The capacity obligation is

calculated for the 100 hours of highest consumption, included

in the PP1 eligibility time slot [07:00; 15:00[ then [18:00; 20:00[,

defined in accordance with the rules, normalising the tempera-

ture gradient to 0 for the reasons explained in chapter 4. ARENH

rights correspond to average rights for the calendar years 2011

and 2012 calculated applying the method applicable in 2015.

ARENH covers 86% of the capacity obligation for

these customers as a whole.

Assuming a capacity price of €10k/MW, the net cost to these

consumers is €0.2/MWh.

A site with this kind of consumption profile and capable of

reducing its consumption by half at peak times can also

transfer the corresponding certificates through the mar-

ket. This results in a gain of €0.8/MWh (assumed capacity

price of €10k/MW), which more than offsets the €0.2/MWh

cost mentioned above, putting this consumer’s net gain at

€0.6/MWh.

Here again, assuming that the security factor is determined with-

out taking into account the contribution of interconnections and

thus set at 1 (instead of 0.93), that each MW of ARENH electricity

produced translates into 1 MW of capacity certificates (instead of

1.15), and that the market capacity price is €30k/MW, the impact

on the consumer’s bill would correspond to an additional cost of

€1.4/MWh233.

Taking flexibility into account again has a substantial impact on

the outcome: if the consumer can reduce its consumption by half

The tables below show outcomes using different hypotheses about the capacity price, the security factor and ARENH certificates.

* Peak consumption reduced by half

WITHOUT DEMAND RESPONSE

€/MWh1 MW of ARENH >1 MW of certificate

1 MW of ARENH >1.15 MW of certificate

C = 0.93 0.1 -0.1

C = 1 0.2 0.0

WITH DEMAND RESPONSE*

€/MWh1 MW of ARENH >1 MW of certificate

1 MW of ARENH >1.15 MW of certificate

C = 0.93 -0.6 -0.8

C = 1 -0.5 -0.7

WITHOUT DEMAND RESPONSE

€/MWh1 MW of ARENH >1 MW of certificate

1 MW of ARENH >1.15 MW of certificate

C = 0.93 0.3 -0.2

C = 1 0.6 0.1

WITH DEMAND RESPONSE*

€/MWh1 MW of ARENH >1 MW of certificate

1 MW of ARENH >1.15 MW of certificate

C = 0.93 -1.7 -2.2

C = 1 -1.4 -1.9

Outcome with an alternative set of hypotheses

Capacityprice:€10k

Capacityprice:€30k

233ARENH covers 70% of the capacity obligation (instead of 86%).

193

CAPACITY MECHANISM IMPACT ASSESSMENTS / 8

The tables below show outcomes using different hypotheses about the capacity price, the security factor and ARENH certificates.

* Peak consumption reduced by half

WITHOUT DEMAND RESPONSE

€/MWh1 MW of ARENH >1 MW of certificate

1 MW of ARENH >1.15 MW of certificate

C = 0.93 0.4 0.2

C = 1 0.5 0.3

WITH DEMAND RESPONSE*

€/MWh1 MW of ARENH >1 MW of certificate

1 MW of ARENH >1.15 MW of certificate

C = 0.93 -0.5 -0.6

C = 1 -0.3 -0.5

WITHOUT DEMAND RESPONSE

€/MWh1 MW of ARENH >1 MW of certificate

1 MW of ARENH >1.15 MW of certificate

C = 0.93 1.0 0.6

C = 1 1.4 0.9

WITH DEMAND RESPONSE*

€/MWh1 MW of ARENH >1 MW of certificate

1 MW of ARENH >1.15 MW of certificate

C = 0.93 -1.3 -1.7

C = 1 -0.9 -1.4

Outcome with an alternative set of hypotheses

Capacityprice:€10k

Capacityprice:€30k

at peak times, its gain will be €2.3/MWh (assumed capacity price

of €30k/MW). The net balance is positive for the consumer, which

will save €0.9/MWh

For large consumers, ARENH-related certificates cover a large share of the obligation generated for their suppliers. The most favourable configu-ration for these consumers (excluding demand response) is a low capacity price, a security fac-tor matching that proposed by RTE and a con-version key above 1 for ARENH rights (i.e. the second hypothesis for this parameter). If large consumers’ flexibility is taken into account, the results are substantially different, as the quantity of certificates will largely exceed the level required to cover the obligation. In sum, the mechanism’s “first-found” impact is very limited for large consumers, and can even be “positive” (n the sense that gains are possible) if consumers leverage their flexibility through the mechanism.

8.3.2.2 Small consumers

The regulations governing the functioning of the retail market are

an important consideration in assessing the mechanism’s impact

on smaller consumers. It is possible to conduct simulations consi-

dering that consumers in this segment will buy electricity at

market rates, though the impact of regulated tariffs remaining in

effect after 1 January 2016 should not be overlooked.

Moreover, residential customers subscribing to the regulated

tariff already pay a capacity-type fee since tariffs have histori-

cally been calculated based on the long-term adaptation of the

mix including a reference to the cost of capacity. A comparison

of the current situation with that resulting from the capacity

mechanism would require comparing these two values. The

issue is more complex for residential consumers buying elec-

tricity from alternative suppliers based on market rates since,

even though the availability of regulated tariffs should result in

an alignment of rates on offer, alternative suppliers source elec-

tricity through ARENH and the market, and must therefore set

their rates by adding various cost components without taking

into account any type of capacity cost. The difference between

194

the two approaches and the price squeeze risks they create are

amply discussed elsewhere and are not addressed in this sec-

tion, but they must be borne in mind to establish the scope of

validity of the orders of magnitude presented below.

By the time the capacity mechanism is in place and consumers

first begin to feel its effects (2016), the applicable tariff system will

have evolved. Article L. 337-6 of the Energy Code stipulates that,

between now and 1 January 2016, tariffs will “gradually be calcu-

lated taking into account the addition of the regulated access to

historical nuclear electricity price, the supplemental electricity

supply cost which includes the capacity certificate, electricity

transmission and marketing costs as well as normal remunera-

tion”. However, the contours of this future tariff system have not

been finalised. It will be the responsibility of CRE (from 2016) to lay

down the applicable principles, within the regulatory framework

defined by the Government.

In the analysis below, it is assumed that the new tariff system is

based on a “market” approach. Rates offered to small consumers

are thus calculated by adding together the different cost compo-

nents: ARENH, a market supplement for energy, the

capacity certificate price, etc. The elements below are

not applicable if regulated tariffs continue to be set on

the basis of costs.

With a “market” approach, the capacity cost com-

ponent, which public authorities currently factor

into regulated tariffs234, will have to be replaced by a

component that refers to capacity certificate prices

set by the market. To provide an order of magnitude

of the sensitivity of the impact on consumers, it is

necessary to formulate a hypothesis about the dif-

ference between the two references for the capacity

cost235. For the purposes of the simulations below,

this difference is set at ± €10k/MW.

Three situations are possible:

> If the difference between the current capacity

price component and the market price is nega-

tive, then the implementation of the capacity

mechanism will, all other things being equal, put

downward pressure on tariffs;

> If there is no difference, the effect on tariffs will be

nonexistent;

> If the difference is positive, the implementation of

the capacity mechanism will result in an increase

in this component within regulated tariffs.

More detailed simulations would have to (i) be based on an

accurate analysis of the capacity component included in regula-

ted tariffs, (ii) factor in the final decisions made by public autho-

rities about the future tariff system, and (iii) use load curves that

are representative of each category or subcategories of consu-

mer (for instance customers on the off-peak/peak tariff.). These

results can thus only be presented once public authorities’ deci-

sions about the future tariff system are known.

In the meantime, broad assumptions can help provide an order

of magnitude of the sensitivity of the impact for small consu-

mers. Considering an overall capacity need in France of 92 GW,

in keeping with the simulations presented in the previous sec-

tion, and that small consumers represent about 165  TWh of

annual energy consumption and thus account for half of this

need, or 46  GW, the value of the capacity certificate for each

MWh consumed works out to 0.28 kW. If ARENH covers half of

this need, then the balance to be covered is 0.14 kW. Based on

a difference of €10k/MW between the average cost of capacity

operated by EDF (excluding historical nuclear) and the market

capacity price, the result is €1.4/MWh.

In other words, if the average cost of the capacity operated by EDF

excluding historical nuclear is €10k/MW below (above) the market

price, then the sensitivity of the impact on the average price paid by a

small consumer, provided that the new tariff setting system is based

on a “market” approach, should be +€1.4/MWh (-€1.4/MWh).

This corresponds to the average between the most temperature sen-

sitive consumers (for instance those that have opted for the peak/

off-peak tariff) and others. In reality, there are likely to be large gaps

between results depending on the consumers considered, for ins-

tance a non temperature-sensitive customer versus one that relies

exclusively on electric heating. As was the case with large consu-

mers, the potential impact can be partly or totally mitigated if a peak

demand management or demand response mechanism is in effect.

234Regulated tariffs must be calculated in such a way as to cover costs. They therefore include a capacity component corresponding to the share of fixed costs associated with generation assets developed and maintained by EDF that cannot be recovered through the energy market. Their structure is based on the theoretical updated generation mix, and takes into account, in this case, a normative capacity cost (which may be different from the real capacity costs) associated with the shortfall risk. See, for example, the CRE report of 4 June 2013 (analysis of EDF's generation and marketing costs relating to regulated electricity tariffs), page 40.

235This method builds on the qualitative analysis included in the impact assessments carried out on the draft NOME Act and presented by the Government in April 2010. See [French Department in charge of Energy and Climate (DGEC), 2013]

The simulations carried out for different con-sumer categories give an idea of the “first-round” effects of the capacity mechanism implemen-tation and the impact the change in approach to setting regulated tariffs will have on small consumers. The mechanism’s financial impact on large con-sumers should be limited. For small consumers, the impact could be positive or negative depend-ing on the difference between the capacity certif-icate price and the capacity component currently

195

CAPACITY MECHANISM IMPACT ASSESSMENTS / 8

8.3.3 Impact on the CSPE

Like all capacities situated within the interconnected French

market, generation facilities that receive public support through

purchase obligations will participate in the capacity mechanism.

These capacities will thus be awarded capacity certificates that

obligated parties can buy. The proceeds will be deducted from

the charges for the public service of electricity financed through

the CSPE, and this deduction will ultimately benefit the consu-

mers subject to this contribution.

To assess the impact of the capacity mechanism’s

implementation compared with the existing situa-

tion, hypotheses must be formulated about the

quantity of certificates that could potentially be allo-

cated to the facilities in question, the capacity price

and the CSPE financing base.

Determining the quantity of certificates that could be allo-

cated to facilities subject to a purchase obligation requires

making an assumption about the subsidised technologies’

penetration when the mechanism is implemented. The figures

below correspond to the installed power estimates for these

technologies in 2017 adopted in RTE’s 2013 Adequacy Fore-

cast Report update:

> Installed wind power: 11.4 GW;

> Installed photovoltaic power: 7.5 GW;

> Cogeneration subject to feed-in tariff: 1.2 GW;

> Renewable embedded thermal: 1.9 GW.

The next step is to determine a quantity of capacity certificates for

each technology applying the provisions in the rules, and notably

the contribution coefficient for intermittent energy sources

based on the values presented in § 5.1. This quantity is multiplied

by a reference capacity price: in keeping with the analytical fra-

mework used until now, this calculation is done considering two

hypotheses (€10k/MW/year and €30k/MW/an).

The results of the impact assessment are summarised in table

5 below.

included in regulated tariffs. In all cases, the cost of the capacity obligation is borne by tempera-ture sensitive consumers alone.In addition to the values presented here, which obviously vary depending on the parameters selected, three observations can be made:> The transfer to alternative suppliers, and

through them to consumers, of the certificates associated with ARENH capacity significantly reduces the cost of implementing the mecha-nism for consumers;> Results are substantially modified when con-

sumers’ flexibility is taken into account, and the mechanism even creates opportunities for gains for the most flexible consumers;> The real impact on consumers will depend on

how suppliers set their rates in a competitive environment: the pricing policies applied to small consumers may differ from the approach to calculating regulated tariffs, and should take into account any capacity they operate them-selves, their commercial strategies, etc. 

Table 5 – Assessment of the impact on the CSPE of the pricing of capacity certificates allocated to technologies subject to a purchase obligation

Installed capacity (GW)

Certificates(GW certified)

Value in €m with price of €10k/MW

Value in €m with price of €30k/MW

Wind power 11.4 2.3 22.8 68.4

PV 7.5 0.4 3.8 11.3

Cogeneration (<12MW) 1.2 1.0 10.2 30.6

Embedded thermal 1.9 1.6 16.2 48.5

Total 22.0 5.3 53.0 158.8

The amounts calculated should be considered in relation to the financing base of the CSPE (forecast domestic consumption (excluding

losses) net of around 380 TWh of energy exempt from the CSPE236).

236Energy Regulatory Commission deliberation of 9 October 2012 on a proposal relative to public electricity service charges and the unit contribution for 2013.

196

The considerations discussed in §  8.3 confirm that the pro-

visions adopted will initially carry a moderate cost for consu-

mers. The studies presented will be useful during the first two

delivery years of the mechanism, when there is unlikely to be

a significant capacity shortage. However, it is important to

stress that this information is indicative only and was collec-

ted during the limited time allotted to the consultation and the

drafting of the rules, while the mechanism parameters were

still subject to modification. These elements must therefore

be viewed only as a first analysis of the consequences of the

capacity mechanism.

When the time comes to implement the rules, it is proposed that

additional tools be used to complement these analyses.

8.4.1 A mechanism simulator made available to stakeholders

For educational purposes, RTE is developing a capacity mecha-

nism simulator called “CLéM”. It is a multiplayer web application

allowing users to “play the part” of a capacity operator, a capacity

portfolio manager, a supplier or a trader. The former estimate the

availability of their capacities, request to have them certified and

seek to maximise the value of the capacity certificates received

over the different phases of the mechanism; the latter estimate

the obligation their customers’ consumption will represent and

buy electricity at the best price on the market or, depending on

costs, initiate peak demand management measures.

8.4 Plans to strengthen the impact assessment system

Depending on the market price, the certification of capacities subject to a feed-in tariff could reduce the charges covered by the CSPE by between €50m and €160m a year, translating into savings of between €0.13 and €0.42/MWh.

Figure 82 – Presentation of CLéM

197

CAPACITY MECHANISM IMPACT ASSESSMENTS / 8

The goal is thus to illustrate the roles of the different players and

the timescales of the mechanism, and to make the microeco-

nomic determinants of the capacity price sensitive by leading

players to a collective trade-off between different options to

ensure that capacity supply and demand are balanced. The first

external session is planned for June 2014.

8.4.2 Expand the “first-round” impact assessment by factoring in small consumers

As discussed in §  8.3, it will be possible to further refine the

impact assessment for small consumers once the new metho-

dology for setting regulated tariffs is known. In its present wor-

ding, the Energy Code leaves several options open, the main two

being a historical vision of accounting cost coverage or a vision

based on the principles of contestability, in which case tariffs will

be determined by adding together independent components

(ARENH, price of wholesale market supplement, price on capa-

city certificate market).

More should be known about these choices within the coming

months (CRE’s remit has been expanded to include tariff sys-

tems). It is possible that the capacity mechanism rules and the

functioning of the capacity market itself could be factored into

the tariff setting formula. In this case, RTE is ready to contribute to

the analyses based on which the tariff formula will be modelled or

to assist with monitoring, within a framework determined by CRE.

8.4.3 Include a study on the dynamic impact of the mechanism over the long term in the assessment

As discussed in § 8.1.2, it is particularly challenging to conduct a

meaningful study of mechanism’s dynamic impact over the long

term due to the difficult choice that must be made between

the accuracy and feasibility of the model. The process involves

evaluating the long-term performances of various market archi-

tectures, taking into account the costs and benefits of each237,

along with factors ranging from the asymmetry of information

between agents or regulatory authorities, factors that can cause

the mechanism to be less efficient than hoped.

It was due to this complexity that a “second-round”

impact study could not be carried out during the

consultation, since the rules must necessarily be

stabilised before such a study can produce meaningful results.

However, it is not because the task is difficult that it must be

skipped, since the results could provide valuable insight to

inform future adjustments to the mechanism.

As mentioned in chapter 1 of this report, RTE is planning to carry

out economic studies on the functioning and impact of the

capacity mechanism within the framework of the role assigned

to it in article 20 of decree 2012-1405 of 14 December 2012.

The results of these studies will be sent to CRE so improvements

can be made to the capacity mechanism and shared with stake-

holders to continue the consultation approach adopted for desi-

gning the mechanism.

These studies will look beyond national borders and take a broa-

der view of security of supply to reflect the integration of Euro-

pean electricity markets. RTE’s models already include several

European countries, for instance for the studies in its adequacy

reports. It could also be possible for these studies to be conduc-

ted in cooperation with other countries, for instance through

a France-German partnership. Collaboration with academics

could also be useful depending on the objectives sought and

methods applied.

The main purpose of these models will be to represent the

impact of the market architecture adopted on investment and

security of supply in European countries. They thus require

a clear picture of the security of supply policies that will be

implemented by European countries. Observation of the capa-

city’s mechanism’s initial functioning will also provide relevant

information for studies and simulations of how it could evolve.

Indeed, the first years will be a learning period for all power sys-

tem stakeholders, and it will be possible to analyse their beha-

viours to improve the mechanism and anticipate the impact it

will have toward 2018-2020.

237[Cepeda & Finon, 2011]

198

9. EUROPEAN INTEGRATION OF THE FRENCH CAPACITY MARKET

9.1 Interconnections’ contribution to security of supply in France

9.1.1 Integrating power systems improves security of supply

By enabling the exchanges of energy between countries, inter-

connections have always contributed to enhance security of

supply in Europe. Indeed, interconnections mitigate the risks on

security of supply at a larger scale than the national one. Impor-

ting energy can therefore be one of the most effi cient solutions

to balance the system, including during periods of system-stress.

This mitigation of risks is all the more important that the

structure of electricity supply is different between European

countries as the risks on security of supply originate from

structurally different issues and can be country-specific. This

leads to a reduction of the correlation of contingencies and

to a greater degree of complementarity or mutual assistance

between countries.

A contingency can be simply defi ned through three characte-

ristics: its probability, intensity and duration. The following taxo-

nomy describes the main contingencies aff ecting security of

supply and proposes an indicative evaluation of their key-cha-

racteristics. This evaluation can diff er between countries.

Figure 83 – Main contingencies aff ecting security of supply

AVAILABILITY OF THERMAL PLANTS

lcpx0 h†xt0 o ctu cxt0 o ck lwkp lwkn0 cq¯ v ugr v0 qev0 pqx0 f †e0

> Probability: HIGH> Intensity: LOW> Duration: VARIABLE

AVAILABILITY OF HYDRO CAPACITY

lcpx0 h†xt0 o ctu cxt0 o ck lwkp lwkn0 cq¯ v ugr v0 qev0 pqx0 f †e0

RES GENERATION

Eolien PV

COLD SPELL/HEAT WAVE

CORRELATIONS

> Probability: LOW> Intensity: MODERATE> Duration: LONG

> Probability: LOW> Intensity: MODERATE> Duration: LONG

> Probability: VERY HIGH> Intensity: LOW> Duration: - PV: LOW - Wind: MODERATE

105 000

99 000

102 000

96 000

93 000

90 000

87 000

84 000

81 000

78 000

75 000

72 000

7:00

14:00

21:0001/12/11

15/12/1129/12/11

12/01/1226/01/12

09/02/1223/02/12

MW

Heure

Jour

102 000 - 105 000

99 000 - 102 000

96 000 - 99 000

93 000 - 96 000

 90 000 - 93 000

 87 000 - 90 000

84 000 - 87 000

81 000 - 84 000 

78 000 - 81 000

75 000 - 78 000 

72 000 - 75 000 

105 000

99 000

102 000

96 000

93 000

90 000

87 000

84 000

81 000

78 000

75 000

72 000

7:00

14:00

21:0001/12/11

15/12/1129/12/11

12/01/1226/01/12

09/02/1223/02/12

MW

Heure

Jour

199

EUROPEAN INTEGRATION OF THE FRENCH CAPACITY MARKET / 9

The exposure to a given contingency differs from one country to

another. This report has already described the peak-load issue in

France (chapter 1). The thermo-sensitivity of the French demand

and its impact on the peak-load during cold spells represent the

main risk on security of supply in France. Contingencies affec-

ting demand are also a concern for other European countries,

such as Sweden, Finland or Hungary.

The level of penetration of renewable energy sources (chiefly

wind and solar) in the energy mix of a given country has a direct

impact on the intensity of the contingency linked to their inter-

mittency, which is considered as low in France. However, in other

countries such as Denmark or Germany, where there is a high

penetration of renewable energy sources, intermittency has

become the main risk on security of supply. As the production

from renewable energy sources depends on weather conditions,

intermittency is by definition a highly probable contingency.

This enhances the need for back-up capacities (be it generation,

demand-response or storage capacities).

Some countries have a large share of hydro generation in their

energy mix – such as Norway, Switzerland or Portugal. There-

fore, drought years constitute a structural risk on their secu-

rity of supply, especially in case of long and severe drought

periods. Drought years can affect security of supply in other

countries. For example, in the Netherlands, where river water is

used to cool thermal power plants, drought years also threaten

security of supply because temperatures of rivers are growing.

Contingencies affecting the availability of thermal plants can

affect security of supply in every single European country. At the

European level, the power system is highly interconnected and

the failure of a plant has a low impact. Nonetheless, at the natio-

nal level, the failure of a plant can have a major impact, espe-

cially in countries where plant sizes are significant compared to

their electricity consumption.

The integration of European power systems mitigates the

risks on security of supply between European countries and

reduces the impact of main contingencies and enables mutual

assistance between countries. This integration is two-fold. On

the one hand, it relies on the “hardware”: the development of

interconnections. On the other hand, it relies on the “software”

in order to enable the efficient use of infrastructure: the mar-

ket design. The European electricity market is a major asset

to ensure security of supply in France and other European

countries.

9.1.2 Recognition of the cross-border dimension in the French capacity market

9.1.2.1 Economic efficiency of the French

capacity market

The efficiency of a market mechanism largely depends on its abi-

lity to accurately reflect the physical state of the system in which

it is implemented. Regarding the energy market, the accuracy of

market coupling mechanisms is directly linked to their ability to

reflect as truthfully as possible the impact of cross-border energy

exchanges on physical energy flows and on the power system. By

the same token, the French capacity market needs to reflect the

contribution of capacities to security of supply, including the inter-

connected system between France and neighbouring countries.

On the one hand, a market-design focusing on the sole contribu-

tion of French capacities or underestimating the contribution of

cross-border capacities to security of supply would result in over-

capacity in France. This overcapacity is costly for the French sys-

tem and therefore sub-optimal from an economic point of view.

On the other hand, a market-design overestimating the contribution

of cross-border capacities to security of supply in France could cause

a capacity shortfall, which means that the adequacy criterion defined

by the government would not be met. This situation leads to a very

high cost of shortfalls and therefore to economic inefficiencies.

RTE is particularly aware of the important contribution of cross-

border capacities to security of supply in France. Indeed, RTE is

legally in charge of the establishment and publication of ade-

quacy forecasts in France and is strongly involded in ENTSO-E’s

work on adequacy report at the regional or pan-European levels.

Therefore, the methodology of its Adequacy Forecast Reports

is based on a detailed model of the Western European power

system238 in order to reflect as accurately as possible the contri-

bution of interconnections to security of supply in France.

9.1.2.2 French and European frameworks

The “loi NOME/NOME law” has recognized the importance of

the cross-border dimension in the French capacity market:

Le mécanisme d’obligation de capacité prend en compte

l’interconnexion du marché français avec les autres marchés

européens.

This provision clearly reflects the willingness to recognise the

European dimension of security of supply in the design of the

capacity market.

238Details of the model used can be found in chapter 10 of this report.

200

The French approach is consistent with European Commis-

sion’s guidelines on generation adequacy in the internal

electricity market. Indeed, the Commission stresses the need

to properly include the cross-border dimension in adequacy

assessments:

Given this increasing integration of electricity markets

and systems across borders it is now increasingly dif-

ficult to address the issue of generation adequacy on a

purely national basis. Member States’ generation ade-

quacy assessments need to take account of existing and

forecast interconnector capacity as well as the genera-

tion adequacy situation in neighbouring Member States.

Surplus generation in neighbouring Member States may

alleviate adequacy concerns; shortages may exacerbate

them239.

The Commission has also included requirements on the need to

recognize the cross-border dimension in capacity mechanisms’

market designs:

[Capacity] mechanisms should be open to any capacity, inclu-

ding capacity located in other Member States, which can

effectively contribute to meeting the required generation

adequacy standard and security of supply240.

9.2.1 Cross-border participation in existing and planned capacity mechanisms

Many European countries have introduced capacity mecha-

nisms (chapter 1) based on different market designs. However,

ACER has underlined in its report on “Capacity remuneration

mechanisms and the internal energy market” that, most of the

time, these mechanisms are purely national schemes:

The existing CRMs are to a large extent tailored to a specific

market situation. As a result there is a large variation in the

existing CRMs’ design features. The experience with cross-

border participation is virtually non-existing241.

For instance, the Spanish and Italian capacity payments

do not provide for a remuneration of cross-border

capacities. Some countries have attempted to address

the issue of the impact of their capacity mechanism

on the energy market (e.g. Ireland’s capacity payment

scheme242) but it can also lead to distortions:

The [Capacity Mechanism] in the SEM takes account

of non-domestic generation by providing that impor-

ters into the SEM receive a capacity payment based

on their volume of imports; exporters from the SEM

9.2 Current status of cross-border participation in capacity mechanisms

pay a capacity payment to the SEM system based on their

volume of exports.

[…]

An example of how specific design choices may lead to a CRM

having a distortive effect on energy market is provided by the

capacity payment scheme operating in Ireland and Northern

Ireland. In this case, the distortions extend to the energy mar-

ket in Great Britain.

[…]

The way the SEM CRM has been designed may raise two chal-

lenges. First, its compatibility with the day-ahead target model for

cross-border trade (market coupling) to be implemented on the

Ireland - Great Britain interconnector. Once market coupling is

implemented it is no longer possible to distinguish which market

participant exports and/or imports and therefore to distinguish

who should receive or reimburse the capacity payment.

Second, and maybe of lesser importance, the ex-post ele-

ment of the capacity remuneration payment induces a risk

for traders and therefore requires a higher price difference

between the SEM and the Great Britain market to trigger

exports, which can impact utilisation of the interconnectors

and affect generation dispatch decisions243.

Swedish and Finnish strategic reserves do not provide for the

participation of cross-border capacities either. For example, in

239[EC, 2013a]

240[EC, 2013a]

241[ACER, 2013]

242[ACER, 2013]

243The electricity markets of Ireland and Northern Ireland are unified through what is called the “Single Electricity Market”, or SEM.

The French capacity market has a cross-border dimension because it makes sense economically and because it is necessary in order to meet legal requirements (both French and European). This prin-ciple should now be declined in the market design and different design solutions can be considered.

201

EUROPEAN INTEGRATION OF THE FRENCH CAPACITY MARKET / 9

Sweden, cross-border participation has not been considered

as a possible option because the capacity mechanism was ori-

ginally designed to avoid the decommissioning of domestic

plants, which were considered as necessary to maintain an ade-

quate level of security of supply.

These examples highlight that the explicit participation of cross-

border capacities is not considered as a priority option in the

design of capacity mechanisms through Europe, regardless of the

type of capacity mechanisms chosen (strategic reserves, capacity

payments...). The participation of cross-border capacities is rather

defined implicitly, most of the time when dimensioning the needs.

For instance, the volume of strategic reserves needed in isolated

systems might be higher than in interconnected ones.

However, in the context of an integrated European electricity

market, the absence of cross-border participation can’t be

considered as a long-term target. Many countries will adapt their

mechanisms. For example, such adaptations are currently being

considered in Spain, Italy and Ireland.

Cross-border participation is an open-issue for capacity mecha-

nisms which are currently under consideration or being imple-

mented in other Member States. No “one-fits-all” solution has

emerged so far. Some explanations on the complexity of this

issue can be found in the United Kingdom’s consultation paper

on “Proposals for the implementation of a capacity mechanism

in the context of the Electricity Market Reform”.

The Government is keen to find a way for interconnected

capacity to be able to participate in the Capacity Market. Parti-

cipation of interconnected capacity would increase efficiency

by increasing competition in the auction, and provide appro-

priate incentives for additional investment in interconnection.

[…]

This is a complex area and we have worked closely with expert

stakeholders, other EU Member States and the European

Commission to explore possible solutions. However despite

this work we have been unable to find a solution that the

Government believes offers a practical solution for the first

capacity auction in November 2014. We continue to work

on this issue however and aspire to finding a solution that is

capable of being implemented at the earliest in time to com-

pete in the 2015 capacity auction244.

While reforming its capacity mechanism, Italy has not directly

addressed the question of cross-border participation. This issue

if left open:

la partecipazione di capacità localizzata all’es-

tero non è prevista dallo Schema di Disciplina.

Tuttavia, in coerenza con le future linee guida

della Commissione Europea, laddove operatori

localizzati sulla rete di un altro gestore di rete

europeo esprimessero, tramite il predetto ges-

tore, l’interesse a partecipare al mercato della

capacità italiano, Terna potrebbe esplorare col

medesimo gestore le eventuali modalità di par-

tecipazione di capacità localizzata sulla sua rete

al fine di delineare una proposta di modifica dello

Schema di Disciplina245.

Lastly, the transposition of mechanisms implemented in other

parts of the world, especially in the United States, can’t be consi-

dered as a proper option (chapter 8). Indeed, major differences

exist between the European and US electricity markets especially

regarding the regulatory framework, the governance framework

and the division of responsibilities between markets parties.

To sum up, there is no practical example of capacity mechanism

targeted on security of supply which allows for the participation

of cross-border capacities in Europe246.

9.2.2 Decision to implicitly recognise foreign capacity in the French capacity mechanism

During the process of designing the future capacity market

in France, the participation of capacities located outside the

French borders has been discussed many times and will be

implicitly recognized as a first step.

Indeed, this question was raised in 2011 during a public consul-

tation led by RTE in the framework of the report on the proposi-

tions for the design of the capacity mechanism commissioned

by the Energy Minister. The report issued in October 2011 advo-

cated that cross-border interconnection could be taken into

account implicitly at a first step, and explicitly in a second step.

Notably prerequisite to allow the explicit participation of

cross-border capacities are not currently fulfilled and an

additional implementation time is required. Consequently,

the explicit participation of cross-border capacities is not

foreseeable in a short-term vision, though RTE would like to

keep it as an “open-option” for the future. Notably if some

neighbouring countries adopt capacity mechanisms similar

to the French scheme, the operational implementation of this

explicit option would be much simpler247.

244[DECC, 2013]

245[AEEG, 2013]

246Germany’s reserve power plant mechanism, ResKV, enables the participation of capacities from other European countries. However, it is designed to secure reserves for the system (congestion management), not to guarantee security of supply.

247[RTE, 2011]

202

The perspective of explicit cross-border participation

was not a minor argument in favor of a decentralized

capacity market, based on tradable certificates. The

report detailed how a market design based on the

exchange of certificates that could be traded as a

commodity, regardless of Members States choices

on the level of security of supply, could offer a bet-

ter prospect for further European integration than

a system based on national auctions. The target is

therefore an explicit participation of cross-border

capacities through cross-border exchanges of capa-

city certificates.

The 2011 consultation listed several potential obs-

tacles to explicit cross border participation and led

to the recommendation of an implicit participation

of cross-border capacities as a first step. These obs-

tacles need to be carefully addressed in order to

consider the explicit participation of cross-border

capacities in the French capacity market:

> Certification and control of foreign capacities;

> Participation of demand-side capacities from

countries where their integration in the market is

not as developed as in France;

> Equivalence of the commitments of foreign and

French capacities;

> Settlement of imbalances for foreign capacities;

> Selection of foreign capacities participating in the

French capacity market;

> Guarantees on the individual contribution of cross

border capacities participating in the French capa-

city market to security of supply in France;

> Limited interconnection capacities require dedica-

ted cross border capacity calculation and alloca-

tion processes;

> Scope of cross border participation, from selected

countries to any interconnected country;

> Involvement of relevant foreign TSOs;

> Involvement of relevant foreign public authorities

in charge of security of supply;

> Consistency in Capacity Mechanisms participa-

tions and avoidance of double counting.

The French National Regulatory Authority, Commis-

sion de régulation de l’énergie, also acknowledged

that the complexity of these issues and that the

implicit participation of cross-border capacities was

an appropriate solution as a first step248.

Based on these considerations and on the relatively short imple-

mentation timeframe of the capacity market, explicit cross-bor-

der participation is ruled out in the first stages of the capacity

market. The 2012 decree provides that:

Interconnections between the French electricity market

and other European markets are taken into account in cal-

culating the capacity obligation; their effect is reflected in

the determination of the security factor, taking into account

the shortfall risk.

The scope of the consultation led by RTE in 2013 was legally

framed by the decree of December 2012. Consequently, the

implicit participation was not questioned as a principle, and only

the different possibilities to implement it were discussed.

This implicit solution already delivers important gains in terms

of economic efficiency, by lowering domestic capacity require-

ments and thus avoiding overcapacities. As such, the participa-

tion of cross-border capacities to the capacity market is model-

led as a positive externality.

This approach does not negatively impact the development of

interconnections as security of supply is also modelled as an

externality in RTE’s network development studies249 (incl. cost/

benefit analysis).

9.2.3 Towards an explicit cross-border participation in capacity mechanisms in Europe

In its Communication “Making the internal energy market

work”250, the European Commission has expressed concerns

about the implementation of national capacity mechanisms

and especially on the potential risk of fragmentation of the inter-

nal market.

Since then, capacity mechanisms are one of the most debated

topics regarding the electricity market design in Europe. The

European Commission along with ACER and industry represen-

tatives have highlighted the need to properly design capacity

mechanisms. This means that their impact on the internal mar-

ket needs to be considered and that the participation of cross-

border capacities needs to be addressed in a near future.

This section of the report gathers the positions of the European

Commission, ACER and Eurelectric regarding the cross-border

participation in order to identify common principles.

248[CRE, 2012]

249The examples cited in chapters 1 and 10 of this report are evidence that interconnection capacity between France and other European countries is being proactively developed.

250[EC, 2012]

251All quotations in this section are taken from the document [EC, 2013a]

252[EC, 2013a] It should be possible to allow capacity equal to the maximum import capacity of the Member State to participate in a national mechanism. This would create a demand for the use of the interconnection which could be marketed by TSOs separately from the normal allocation of cross border capacity.

253[EC, 2013a] Alternatively, long term allocation capacity on interconnectors could allow for cross-border participation in capacity mechanisms by allowing generators to demonstrate their ability to deliver electricity to the Member State in question.

254[EC, 2013a] Long term allocation capacity on interconnectors could allow for cross-border participation in capacity mechanisms by allowing generators to demonstrate their ability to deliver electricity to the Member State in question. […] With reliability options the incentive effect of the option should ensure that generators located in other Member States would anyway ensure they had sufficient interconnection capacity rights.

203

EUROPEAN INTEGRATION OF THE FRENCH CAPACITY MARKET / 9

9.2.3.1 European Commission

The European Commission has recommended the explicit parti-

cipation of cross-border capacities in capacity mechanisms in its

Staff Working Document “Generation Adequacy in the internal

electricity market - guidance on public interventions”, accom-

panying the Communication “Delivering the internal electricity

market and making the most of public intervention”251:

[Capacity] mechanisms should be open to any capacity, inclu-

ding capacity located in other Member States, which can

effectively contribute to meeting the required generation

adequacy standard and security of supply.

However, the Commission has recognized that the implicit par-

ticipation of cross-border capacities could be considered, as a

temporary solution:

[I]t may be necessary, as an interim step, for Member States to

calculate the contribution of imports to meeting the genera-

tion adequacy standards.

The Commission has proposed two possible solutions for the

explicit participation of cross-border capacities in capacity

mechanisms. Both solutions are based on the hypothesis that

the cross-border participation of capacities should be limited to

the physical import capacity of a given country.

It should be possible to allow capacity equal to the maximum

import capacity of the Member State to participate in a national

mechanism. This would create a demand for the use of the inter-

connection which could be marketed by TSOs separately from

the normal allocation of cross border capacity252. Alternatively,

long term allocation capacity on interconnectors could allow for

cross-border participation in capacity mechanisms by allowing

generators to demonstrate their ability to deliver electricity to

the Member State in question253.

Both options are designed in order to manage scarcity situations

while taking into account realistic physical imports. However,

they can lead to very different results, since the volume of long-

term physical transmission rights allocated to market parties is

significantly below the maximum import capacity. Indeed, long-

term capacity calculation is subject to a high-degree of uncer-

tainty and therefore, the effective import capacity can only be

known as real-time approaches.

The management of scarcity situations is one of the main

challenges raised by the design of a cross-border capacity

mechanism. However, it is not the only issue that

needs to be addressed by the market design.

Indeed, it is crucial to design a solution in which

the contribution of cross-border capacities parti-

cipating to a given mechanism is guaranteed with

regard to security of supply in this country. The

European Commission has also stressed this issue

and defined it as the “effective contribution” of

cross-border capacities to security of supply. Such a

definition can also be found in the NOME law.

The Commission suggests two ways to address this

issue of “effective contribution”: a system based on the

allocation of interconnection capacity rights (financial

or physical) or a system involving “reliability options”254.

Both proposals are worth exploring, but could create

ties between capacity and energy markets.

The European Commission has recognised that the

explicit participation of cross-border capacities is a

complex issue and that it requires further and careful

attention from Member States and stakeholders255.

Notably, the Commission has highlighted the need

to avoid double-counting if a given capacity partici-

pates in several mechanisms simultaneously256.

Based on this diagnosis, the Commission has recom-

mended the establishment of a regional cooperation in

order to properly address those questions and issues257.

9.2.3.2 ACER

In its report on “Capacity remuneration mecha-

nisms and the internal market for electricity”258, the

Agency for the Cooperation of Energy Regulators

(ACER) has supported the participation of cross-

border capacities in capacity mechanisms, while

recognising the difficulties linked to its implementa-

tio259. ACER has defined these practical difficulties and proposed

potential solutions in point 45 of its report:

Cross-border participation to CRMs does not necessarily require

that cross-border capacity is set aside. However, it requires a

strong coordination of national security of supply policies and

the fulfilment of additional conditions, namely that:

a) the TSO, in whose jurisdiction the CRM is implemented,

is able, directly or through the adjacent TSO, to monitor the

actual availability of the (capacity) resources committed by

foreign provider over the contracted period and that the

255[EC, 2013a] The Commission Services recognise there may be practical difficulties of implementing a framework for cross border certification of capacity and accounting for “capacity” import and export. […] The Commission Services will continue to work with Member States, ACER and National Regulatory Authorities, and ENTSO-E and TSOs to examine how cross border trading can be facilitated in capacity mechanisms.

256[EC, 2013a] Obviously generation abroad or interconnector capacity should not be double-counted or double remunerated.

257[EC, 2013a] Regional cooperation would facilitate addressing this problem and should be pursued where possible.

258All quotations in this section are taken from the document [ACER, 2013]

259[ACER, 2013] In the case of national [Capacity Mechanisms], greater efficiency could be achieved and the distortion of the IEM minimised by assuring participation – to the extent possible – of adequacy and system flexibility resources provided by generators and load in other jurisdictions. The challenges to this are however significant.

204

foreign provider is able to provide the same level

of commitment with respect to security of supply

than a local provider;

b) efficient cross-border allocation mechanisms are

implemented on all timeframes, in particular in the

day-ahead, intra-day and balancing timeframes;

c) MSs accept that their national resources (e.g.

generation plants) are partly contracted to ensure

the security of supply of a neighbouring MS and

guarantee that providers will not be hindered in

exporting at any moment in time, i.e. TSOs do not

deviate from their routine in offering cross-border

capacity in particular in stressed situation on both

sides of the border.

According to ACER, in order to enable the explicit

participation of cross-border capacities, Member

States must recognise that part of their national

resources are contracted to ensure security of

supply of a neighbouring Member States and

guarantee that there will be no export restriction

including during stress events260.

To that extent, ACER has underlined a lack of

coordination between Member States on secu-

rity of supply issues261 and made the following

recommendations:

I. the harmonisation of generation adequacy

criteria and security of supply levels should be

undertaken where possible;

II. a common (at least regional) and coordina-

ted approach for a thorough security of supply

assessment should be implemented.

9.2.3.3 Eurelectric

Numerous stakeholders have contributed to the

debate on cross-border participation in capa-

city mechanisms. Eurelectric has notably pres-

ented a possible solution during its conference

of December 2013: “Future electricity markets

with or without capacity mechanisms: What

does Europe say?”262

Like the European Commission and ACER,

Eurelectric has advocated for cross-border

participation in capacity mechanisms263 and

acknowledged the complexity of the issue264.

Eurelectric has made a detailed proposition of market design in

order to enable cross-border participation in capacity mechanisms.

This proposition aims at defining key principles for such a design

but needs to be further assessed, especially regarding operational

aspects. The key elements of this proposition are as follows:

> All participants (national or foreign) in a CRM must fulfil the

same requirements and market rules in relation to e.g. cer-

tification, penalty regime, availability requirements, energy

producing requirements, etc.

> It should not be possible to participate with the same capa-

city in more than one CRM at a time. Each MW in the CRM

cannot be committed twice and receive double earnings.

Therefore it should also be possible for capacity providers

to “opt out” of their national scheme in order to instead par-

ticipate in a mechanism established elsewhere.

> TSOs should bear the responsibility of proposing the

amount of cross-border interconnection capacity volume

that can be offered for CRM cross-border participation. This

amount should be approved by the relevant regulators. The

higher the amount, the more competition from foreign par-

ticipants will be possible in the national CRM.

> There would be a separate congestion rent for the CRM

cross-border capacity allocation. This congestion rent

should be used in the same way as the energy congestion

rent from forward and day-ahead allocation. This means

that the benefit from cross-border capacity and energy tra-

ding will be considered when calculating the benefit of new

transmission investments.

> There should be no cross-border capacity reservation for

CRM: cross-border participation in a CRM should have no

influence on the cross-border allocation for forward, day-

ahead, intra-day and balancing markets.

Eurelectric has also explored options in terms of market design

to allow cross-border exchanges of capacity products including

the allocation of cross-border interconnection capacity. This

proposed model is based on the same principles as the day-

ahead market coupling ones265.

The paper presents examples of implementation of such

models, including a schematic vision of cross-border trades in

different market situations.

Lastly, Eurelectric has recommended greater coordination

on security of supply in Europe to allow cross-border capacity

mechanisms to work efficiently266.

260[ACER, 2013] Without such a guarantee, the foreign provider would not be able to deliver the same level of commitment with respect to security of supply than a local provider.

261[ACER, 2013] The Agency observes […] that MSs currently have national and diverging approaches to security of supply with a lack of coordination among them.

262The quotations in this section are taken from the accompanying note to this presentation [Eurelectric, 2013]

263[Eurelectric, 2013] EURELECTRIC agrees with the European Commission that national capacity remuneration mechanisms (CRM) should be open to cross-border participation.

264[Eurelectric, 2013] We believe that it is possible to let capacity providers from other bidding zones participate in capacity mechanisms using market-based procedures. […] EURELECTRIC recognises the complexity of the [Capacity Mechanism] cross-border participation concept.

265[Eurelectric, 2013] A possible design for CRM cross-border participation could be based on the same principles as Day-Ahead market coupling. Two situations are possible:- CRM is based on central auctions to set the value of the CRM: The cross-border capacity for participation in CRM could be allocated implicitly during a common auction to determine the CRM price in different bidding zones.- CRM is not based on auctions, but on other mechanisms: The cross-border capacity for participation in CRM could be auctioned separately (explicit auction). In both situations, cross-border capacity will be allocated by TSOs several times for two purposes:1) to use resources (generation, demand response, storage) from two or more bidding zones to ensure adequacy […]2) to ship energy […]Congestion rent accumulated during these two auctions should be essentially used for building cross-border interconnection capacity.

205

EUROPEAN INTEGRATION OF THE FRENCH CAPACITY MARKET / 9

To ensure consistency between the French legal framework and

recent guidelines from the European Commission, RTE proposes

a roadmap on cross-border participation. Based on a three-step

approach, this roadmap enables the implementation of the

French capacity market on schedule with an implicit participa-

tion of cross-border capacities while investigating on practical

evolutions in order to reach the target of explicit cross-border

participation.

> Step 1: Implicit cross-border participation

In accordance with the provisions of Decree 2012-1405 of

14  December 2012 creating a capacity obligation mechanism ,

the rules of the French capacity market provide for the implicit

participation of cross-border capacities. This cross-border partici-

pation is based on the representation of the positive impact of

interconnections on security of supply and leads to a reduction of

the obligation of suppliers in the capacity market.

> Step 2: Public consultation on cross-border participation

In accordance with the provisions of Decree 2012-1405 of

14 December 2012 , the rules of the French capacity market267

entrust RTE with the responsibility of proposing potential evo-

lutions of the market design regarding cross-border participa-

tion. To that extent, RTE will launch a public consultation regar-

ding cross-border participation in the French capacity market.

Following this consultation process and its outcomes, RTE will

9.3 A practical way forward for explicit cross-border participation

report to the French National Regulatory Authority and the

Energy Minister on potential evolutions of the French capa-

city market design regarding cross-border participation no

later than ten months after the entry into force of the French

capacity market rules. These propositions should include the

design of a target towards explicit cross-border participation

and can be based on a step-by-step approach to implement

this target.

This roadmap paves the way towards explicit cross-border partici-

pation in the French capacity market (incl. a timeline to conduct

this work).

Prior to the consultation process and in order to foster concrete

propositions on cross-border participation, RTE is conducting

internal studies on this topic and shares forward-

looking principles on explicit cross-border parti-

cipation in this report.

> Step 3: Evolutions of the French capacity

market design

In order to implement evolutions of the French

capacity market design regarding cross-border

participation, amendments to the decree of

December 2012 might be required.

266[Eurelectric, 2013] [Capacity Mechanisms] should be […] underpinned by close coordination between Member States and respective transmission system operators (TSOs). […] EURELECTRIC […] pleads for harmonisation/coordination of national CRMs to facilitate participation of foreign generation, demand response and storage.

267Article 5.2.3.4.

The European debate on capacity mechanisms has grown in 2013, especially regarding the design of cross-border participation. Common principles have been elaborated by different stakeholders in order to tackle the issue of explicit cross-border participation:

> Capacities participating in a given capacity mechanism need to have an effective contribution to security of sup-ply of the dedicated country;

> The participation of cross-border capacities to different capacity mechanisms needs to be properly designed in order to be consistent and effective ;

> Cross-border participation should be limited to the effective physical import capacity;

> A regional cooperation framework on security of supply needs to be agreed upon by Member States and TSOs.

Currently, no capacity mechanism has implemented a solution for the explicit participation of cross-border capaci-ties. This underlines the complexity and the numerous challenges raised by this issue.

This European debate on capacity mechanisms has arisen during the last consultation process on the French capacity market, which was framed by the 2012 decree’s provision on the implicit participation of cross-border par-ticipation. Taking into account both the European and the French context, RTE proposes to pave the way towards explicit cross-border participation in the French capacity market through a dedicated roadmap.

206

Therefore, and as proposed by RTE, a step-by-step approach

seems to be an efficient way forward as it enables the relatively

quick implementation of transitory solutions. A transitory solu-

tion can be defined as the phase between the current implicit

cross-border participation and the target (the so-called “full”

explicit cross-border participation).

As all prerequisites for a go-live of the target might not be fulfil-

led simultaneously on all borders and, especially, depend on the

implementation of a cooperation framework between Member

States at a regional level, there is a chance of overlapping between

explicit and implicit cross-border participation solutions. In such a

case, it will be important to avoid double counting.

Any form of explicit cross-border participation requires an effec-

tive contribution of foreign capacities to security of supply of

the country in which the capacity mechanism is implemented.

However, the definition of effective contribution may differ in

the target (“full” explicit cross-border participation) or in a tran-

sitory solution. In this regard, during the implemen-

tation of a transitory solution, explicit participation

of cross-border capacities to the French capacity

market should be limited to capacities which are also

participating to the French balancing mechanism268.

The integration of the energy market has shown the

efficiency of the “regional” approach for cross-border

projects. This approach is based on the cooperation

of a set of countries within an electricity regional ini-

tiative and the progress reports of those initiatives in

terms of market coupling are of crucial importance for

the completion of the target model at the EU level.

268This will nonetheless require a change to the method of accounting for foreign bids currently applied in the French balancing mechanism. Changes made to the balancing mechanism following the implementation of the Electricity Balancing Code will also have to be taken into account.

269Bundesverband der Energie- und Wasserwirtschaft.

Figure 84 – Roadmap on cross-border participation in the French capacity market

Step 1 Implicit

Step 2 Consultation

Step 3 Modifications

Transition Intermediate model Target model

Publication of capacity

mechanism rules +10 months

The French and German governments, along with stakehol-

ders from both countries, have recently called for greater

Franco-German cooperation in the area of electricity. To that

extent, the Union française de l’électricité and its German

counterpart  – BDEW269  – have elaborated, along with their

members, a work program in order to identify common sub-

jects of interest and cooperation. Their goal is notably to pro-

mote mutual understanding on security of supply issues and

to foster electricity market reforms in order to tackle those

issues.

RTE has included forward-looking principles on explicit cross-

border participation in this report. These principles are the

outcomes of early discussions on explicit cross-border parti-

cipation in the French capacity market. They constitute a raw

material elaborated in order to prepare the public consultation

process provided for in article 5.2.3.4 of the French capacity

market rules.

Contrary to the French capacity market rules, these principles

have not yet been shared and discussed with stakeholders. It will

be the scope of discussion of the public consultation on cross-

border participation. Such a discussion will necessary have to be

challenged at a regional level.

The points discussed in this section should be considered as RTE’s prospective contribution to the European debate on cross-border partici-pation in capacity mechanisms, and go beyond the current legal framework implementing the French capacity market.

207

EUROPEAN INTEGRATION OF THE FRENCH CAPACITY MARKET / 9

degree of uncertainty regarding the implementa-

tion timeframe of explicit cross-border participation

or even question the ability to implement it at all.

Moreover, harmonising security of supply criteria in

Europe would not necessarily make sense from an

economic point of view. Defining a common value of

lost load that could be agreed upon by all countries

despite their differences seems very unlikely. Indeed,

European countries have structural differences: their

economy, their energy mix, their structure of energy supply and

their exposure to risks on security of supply. Therefore, a constrained

harmonisation of security of supply criteria could lead to economic

inefficiencies. Moreover, it is worth underlining that a regional har-

monisation does not solve the issue as the interface between these

regional security of supply still needs to be addressed.

9.3.1.3 Economic efficiency and real value for security

of supply in concerned countries

The design of an explicit cross-border participation solution

should be seen as an opportunity to improve the economic

efficiency of capacity mechanisms. To that extent, it is worth

acknowledging that implicit cross-border participation already

is an efficient solution as the positive impact of interconnections

is valued through a reduction of the obligation of suppliers and

therefore avoid a situation of overcapacity in France. This effi-

ciency will be further enhanced by:

> The completion of the energy market;

French stakeholders have been strongly involved in electricity

regional initiatives, including for innovative projects272. This has

led to an early and significant level of integration of the French

market with its neighbours.

> Improved adequacy assessments;

European TSOs, within ENTSO-E, are currently working on the

improvement of their adequacy assessments at the European

level. This work is a step in the right direction to reach this objec-

tive. At the French level, RTE’s adequacy assessments comply

with the guidelines from the European Commission273.

9.3.1 Key principles to design a solution for explicit cross-border participation

Cross-border participation in capacity mechanisms is a complex

subject that needs to be tackled while considering the target

model for the European electricity market. Therefore, in order to

design and implement a solution for cross-border participation,

it is important to have a common understanding on high-level

design principles and on the challenges that need to be tackled.

9.3.1.1 Preservation of the internal energy market

The progressive integration of the internal energy market is a

major success for Europe. Security of supply in Europe is also

enhanced by the optimisation of cross-border trades through

market coupling mechanisms. The European Commission has

outlined the benefits of the internal energy market in its Com-

munication “Making the internal energy market work”270.

These breakthroughs towards the integration of the internal

energy market have required several years of intensive work and

are not yet completed. To that extent, any market design evo-

lutions driven by the implementation of capacity mechanisms

needs to be done while preserving the internal energy market

and its benefits271. This applies both for the implementation of

capacity mechanisms at the national level or for the design of

explicit cross-border participation solutions.

9.3.1.2 Compatibility of Member States’ competences

and choices

The Lisbon Treaty provide for the division of competences

between the European Union and Member States and energy is

defined as a shared competence. Moreover, the Treaty specifies

that Union energy policy measures shall not affect a Member

State’s right to determine the general structure of its energy sup-

ply. This means that the final responsibility with regard to security

of supply issues remains national (incl. security of supply targets).

A review of this division of competences would require major legal

amendments, possibly up to the European treaties.

Therefore, explicit cross-border participation in capacity mecha-

nisms should not be conditioned to a pan-European harmonisa-

tion of security of supply criteria. Indeed, it would create a high

270[EC, 2012]

271See section 10.2 of this report for a discussion of the absence of provisions in the French capacity mechanism that would disrupt energy markets.

272See chapter 10 of this report.

A solution for explicit cross-border participation in capacity mechanisms must be compatible with Member States’ competences as provided for in the Lisbon Treaty. Therefore, it should also be respectful of their (different) choices in terms of security of supply.

Preserving the internal energy market and its benefits is a crucial principle to take into account while designing solutions for explicit participation in capacity mechanisms.

208

Explicit cross-border participation to the French

capacity market could increase its economic effi-

ciency as it will enlarge the choices of investors

regarding the location of capacities.

However, explicit cross-border participation only makes sense if the

effective contribution of a capacity to security of supply in a country

is not impacted by the geographical location of this capacity. It is

not enough to enable capacities to participate in a capacity mecha-

nism: the underlying physical reality must be similar, regardless

of the location of these capacities (domestic or cross-border). In

other words, a capacity should be able to choose the geographical

zone in which it will effectively contribute to security of supply. This

choice should be consistent with the geographical scope of the

capacity mechanism in which this capacity participates.

ACER has made a similar observation274:

Cross-border participation to [Capacity Mechanisms requires

that] […] MSs accept that their national resources (e.g. genera-

tion plants) are partly contracted to ensure the security of sup-

ply of a neighbouring MS and guarantee that providers will not

be hindered in exporting at any moment in time, i.e. TSOs do

not deviate from their routine in offering cross-border capacity

in particular in stressed situation on both sides of the border.

[…]

Without such a guarantee, the foreign provider would not be

able to deliver the same level of commitment with respect to

security of supply than a local provider.

Explicit cross-border participation in the French capacity market

will only lead to an increased economic efficiency if cross-bor-

der capacities can effectively and physically contribute to secu-

rity of supply in France. This means that:

> A certified cross-border capacity should be available during periods

of system stress. This availability should be subject to a control;

> The level of certified cross-border capacities should be com-

patible with the import capacity of interconnections;

> Certified cross-border capacities for a given capacity mechanism

should be committed to contribute to security of supply in this

country even in cases of simultaneous shortage in several countries.

9.3.2 Relevant event to be considered to allow effective cross-border exchanges of capacity products

The expected outcome of explicit cross-border participation in a

capacity mechanism is to be able to rely on imports when security

of supply is threatened. This implies that the definition of a capa-

city product tradable cross-border and the associated market

design cannot be separated from a broader discussion over secu-

rity of supply and the way it is ensured in a market environment

at the European level.

In most cases, the way cross-border capacities could contribute

to security of supply of a given country – like France – is straight-

forward: power flows indicated by the market coupling algorithm

would most certainly be directed towards the country facing the

risk of shortage. This means that current markets already provide

for the participation of cross-border capacities to security of sup-

ply – albeit in an aggregate form and without any kind of guarantee.

This explains why the implicit solution considered so far is in itself

already a fair way to consider the interconnection of countries.

However, capacity mechanisms are precisely implemented to ensure

the effective contribution of capacities to security of supply. In a way,

the capacity mechanism works like an insurance policy. As the consu-

mer pays for insurance, he needs to be granted an insurance cover.

The effective contribution is the cover granted to consumers as they

pay for security of supply. Explicit cross-border participation solutions

need to provide this “insurance” cover to the system or will be ineffi-

cient. To properly assess this issue, it is necessary to consider events

during which the current markets do not spontaneously direct energy

flows towards countries that have chosen to cover their consumers

towards risks on security of supply through a capacity mechanism.

Indeed, in some specific situations, it is not sure that the natural out-

come of energy markets will lead to optimal flows between areas.

This is notably the case when there is a shortage in two countries

simultaneously: what should happen to the capacity contracted

through a capacity mechanism and the energy it generates? The

market coupling algorithm might not be able to clear in those situa-

tions. Indeed, in case of simultaneous shortages, the market situa-

tion will probably result in a lack of offers of energy bids (included “at

any price”) to meet the demand. In those cases where the market

does not clear, the allocation of bids might not be accurate despite

their key role regarding the energy flows between countries.

In those situations, specific provisions could be required to handle

power flows properly and ensure that they benefit to consumers

on the basis of what they have paid for security of supply. Such

273See chapter 10 of this report.

274[ACER, 2013]

As for domestic generation or demand-side capac-ities, the effective contribution of cross-border capacities to security of supply in the country in which the capacity mechanism is implemented is a crucial point to be addressed.

209

EUROPEAN INTEGRATION OF THE FRENCH CAPACITY MARKET / 9

provisions would constitute a clear basis for cross-border partici-

pation in capacity mechanisms, and would be impacted by cross

border exchanges of capacity.

In order to be efficient and credible, these provisions need to be

embedded in a broader cooperation framework on security of sup-

ply and especially on the management of shortage situations. Such

a cooperation framework could be negotiated and implemented by

transmission system operators with the approval of national regu-

latory authorities and under the control of Member States. Along

with market arrangements, it needs to include provisions on opera-

tional issues and could be completed by cooperation agreements

at Member State level, especially bilateral agreements to ensure a

faster implementation (for example between France and Germany).

These cooperation frameworks need to be consistent with Mem-

ber States’ competences regarding the structure of their electricity

supply as defined by article 194 of the Lisbon Treaty, and especially

without considering harmonisation of security of supply criteria as

a prerequisite. The Commission de régulation de l’énergie has also

stressed the importance of European coordination regarding expli-

cit cross-border participation in the French capacity market275.

9.3.3 “No-go” solutions to implement explicit cross-border participation

Cross-border capacities contribute to security of supply in France

through interconnections, of which transfer capacity is limited.

The potential of their contribution is therefore constrained, and

there are situations in which an additional cross-border capacity

will not bring any improvement to security of supply in France

because interconnections are already fully used. This physical

limitation needs to be properly addressed in the design of a solu-

tion to ensure explicit cross-border participation in the French

capacity market.

Various solutions can be considered as able to ensure the effec-

tive contribution of cross-border to security of supply. Although

intuitive, two options must be ruled out: the use of physical trans-

mission rights and the reservation of interconnection capacity.

9.3.3.1 Use of physical transmission rights (PTR)

Intuitively, one could consider that holding, or even nominating,

PTRs is a sufficient solution to ensure the effective contribution of

cross-border capacities to security of supply in France276.

However, while PTRs provide for an entitlement to use part of

the available cross-border transmission capacity at a point in

the future to flow energy between countries, they are not a

necessary prerequisite for cross-border trading.

Indeed, the European target model for electricity

provide for two different types of auctions. In the

day-ahead timeframe, transmission capacity and

electricity are traded together through implicit auc-

tions. It completes the explicit auctions where capa-

city (PTR) and electricity are traded separately in the

long-term timeframe.

Moreover, nominating PTRs is not a sufficient condi-

tion to guarantee the direction of a power flow.

Indeed, as capacity is allocated in different time-

frames (long-term, day-ahead, intraday), the aggre-

gated balance of flows provide for the direction and

volume of power flows. To that extent, an individual

stakeholder nominating a PTR can’t guarantee the

physical flow linked to this commercial exchange.

This particular point has been detailed in RTE’s 2011 report to the

Energy Minister on the main design principles of the French capa-

city market277.

Holding PTRs is a neither necessary nor sufficient condition to

ensure the effective contribution of cross-border capacities to

security of supply in a given country. This design solution for

cross-border trades of a capacity product must be ruled out.

9.3.3.2 Reservation of interconnection capacity

Reservation of interconnection capacity could also be considered

as a potential design solution for explicit cross-border participa-

tion. However, this solution has an obvious negative impact on

energy trades and might not be compatible with the existing legal

provisions on the allocation of interconnection capacity278.

Though this solution could guarantee the effective contribution

of cross-border capacities to security of supply, it does not pres-

erve the European energy market. Reservations of interconnec-

tion capacity would limit the possibility for cross-border energy

trades, disturb the optimisation process of trades and therefore

lead to economic inefficiencies.

Considering this solution would nonetheless be justified if capa-

city and energy trades were exclusive goods, i.e. if capacity trades

automatically precluded energy trades.

However, at the national level, generation plants can trade capa-

city certificates through the capacity mechanism without lowe-

ring their energy outputs or restraining their ability to participate

275[CRE, 2012] Stronger cooperation between Member States, system operators and regulators appears crucial to guarantee that the tools implemented are similar and coordinated or, failing that, to ensure that different mechanisms can interact effectively.

276PTRs are “physical transmission rights with a use-it-or-sell-it condition”.

277[RTE, 2011]

278See, among others, the provisions of the Network Code for Capacity Allocation and Congestion Management.

210

in the energy market. This means that a “security of supply” pro-

duct and an energy one are not exclusive goods.

By the same token, cross-border trades of “security of supply” pro-

ducts – in other words capacity products – do not compete with cross-

border energy trades. To that extent, to ensure the effective contribu-

tion of a capacity to security of supply in a given country, reservation of

interconnection capacity appears to be an excessive solution.

To sum up, reservation of interconnection capacity is a sufficient

but not necessary condition to ensure the effective contribu-

tion of cross-border capacities to security of supply. Moreover, it

would probably a distortive solution with regards to the European

energy market outcomes. As this solution is not a necessary one

and leads to economic inefficiencies, it should be ruled out.

9.3.4 Target solution for explicit cross-border participation in the French capacity market

The design of a market solution to allow explicit participation

and effective contribution of cross-border capacities in capacity

mechanisms need to respect ground principles. Based on inter-

nal studies, RTE has defined 5 main design conditions and shares

them in the following section

RTE considers that it is possible to allow explicit cross-border par-

ticipation in the French capacity market:

> Without harmonising security of supply criteria between

Member States (condition 1).

A solution for the explicit cross-border participation in capacity

mechanisms must be compatible with Member States’ competences

as provided for in the Lisbon Treaty. A review of this division of com-

petences would require major legal amendments, possibly up to the

European treaties, and should therefore not be questioned, especially

to allow a fast implementation of explicit solutions. Moreover, from an

economic point of view, national security of supply criteria accurately

reflect a Member State’s specific situation and might therefore be

more efficient than a European harmonised criterion

> Without reserving interconnection capacity (condition 2).

This point was discussed in paragraph 9.3.3.2. Reserving intercon-

nection capacity would go against the principles of the internal

market and reduce the economic optimisation enabled through

energy trades. Indeed, capacity and energy are not exclusive pro-

ducts. This means that participation in the capacity mechanism

does not preclude participation in energy markets. Likewise,

cross-border capacity trades and cross-border energy trades are

not exclusive. This solution therefore seems sufficient to ensure

the effective contribution of cross-border capacities to security of

supply in France but is disproportionate.

> Limited to the effective physical import capacity and based

on market rules (condition 3).

Cross-border capacities can contribute to security of supply in France

through interconnections. Their contribution therefore cannot

exceed the import capacity of interconnections between France and

its neighbours. This physical limitation needs to be address through

a market-based allocation process of the interconnection capacity.

Moreover, to ensure the effective contribution of cross-border

capacities to security of supply in France, these capacities need to

be available during system stress events in France.

RTE also considers that the target model for explicit cross-border

participation in the capacity market should allow trades of capa-

city products and be consistent with cross-border energy trading

mechanisms. The implementation of this target model is possible:

> If a cross-border certification or control process is in place

(condition 4).

Explicit cross-border participation in the French capacity mar-

ket will require a dedicated and robust market architecture that

reflects the specific characteristics of “capacity” as a product

along with the various aspects of security of supply.

Cross-border capacity trades can only be efficient if there is a

cross-certification process between Member States or if conver-

sion keys different “capacity” products are defined. This is a prere-

quisite to ensure the effective contribution of cross-border capa-

cities to security of supply in a given country.

If cross-border trades does not include such arrangements, there will

be no certainty towards cannot the effective contribution of capaci-

ties to security of supply and thus these types of solutions should not

be considered as a way-forward for the future market design.

> If cooperation frameworks are in place to manage shortage

situations (condition 5).

As discussed in § 9.3.2, widespread shortage situations should be

considered as reference events to assess the effective contribu-

tion of cross-border capacities to security of supply in another

country. These specific events can be defined as a situation when

a shortage situation in one country creates a shortage situation in

other countries (a sort of snowball effects) or in case of simulta-

neous shortages in two countries.

211

EUROPEAN INTEGRATION OF THE FRENCH CAPACITY MARKET / 9

In such situations, a cooperation framework on security of sup-

ply and especially on the management of shortage situations is

required. Such a cooperation framework could be negotiated and

implemented by transmission system operators with the approval

of national regulatory authorities and under the control of Mem-

ber States. This cooperation framework would allow the proper

management of widespread shortage situations and the effective

contribution of cross-border capacities to security of supply.

The fulfilment of these conditions requires a major regional coordi-

nation. The agreement of cooperation frameworks on security of

supply will notably require an intense work between Member States,

national regulatory authorities and transmission operators. To that

extent, it makes sense to consider a transitory solution for the explicit

cross-border participation with a shorter implementation timeframe.

9.3.5 Shaping a transitory solution

Whereas the target solution will require significant preliminary work,

it could be possible to introduce a transitory solution in the rela-

tively near future. Though it would be imperfect and designed to

be ultimately replaced by the target solution, a transitory solution

could truly improve the design of the capacity market, provided

that it offers real benefits in terms of security of supply. As discussed

above, in the absence of a cooperation framework ensuring that

conditions 4 and especially 5 are met, it will be necessary to define

another process to ensure the effective contribution of cross-bor-

der capacities to security of supply. This control process could be

based on existing market mechanisms and could entail:

> The mandatory participation of cross-border capacities in

the French balancing mechanism (condition 6, which can be

substituted for conditions 4 and 5)

Explicit cross-border participation needs to rely on the effective

contribution of cross-border capacities to security of supply. If it

does not, the credibility of the entire process will be called into

question. As in France, cross-border capacities need to have avai-

lability commitments. In the absence of such a commitment, it will

not be possible to check their effective contribution to security

of supply. Moreover, an availability commitment limited to a few

GW of capacities located in a foreign country has no added-value

on security of supply in France. Indeed, this size of this capacity is

insufficient to cover the needs in its own country in case of shor-

tages. Therefore, the method of participation and the definition

of commitment need to be adapted for cross-border capacities.

In this regard, the direct or indirect participation of cross-border

capacities in the French balancing mechanism could ensure,

albeit imperfectly, their effective contribution to security of sup-

ply and to the reduction of the shortfall risk in France (substitute

for condition 5). The participation of cross-border capacities in

the French balancing mechanism would also allow cross-border

capacities to have similar verifications and controls as the French

ones (substitute for condition 4).

This option could even be pushed further based on a reciprocity

principle applied to Member States that have introduced a capa-

city market with availability commitments. Through a mutual

recognition of capacity mechanisms and ensuring the absence of

double counting, this system could allow cross-border capacities

to participate in the French capacity market and to French capaci-

ties to participate in other capacity mechanisms.

If a transitory solution is adopted and conditions 4 and 5 are removed,

provisions would still be required to ensure that condition 3 is met.

This means that the physical limit of interconnection import capacity

needs to be taken into account. Such provisions could be designed

as transmission rights dedicated to capacity markets. Some stakehol-

ders have recently suggested a solution along these lines. The idea is

for suppliers to hedge part of their obligations with interconnection

transmission rights, which would be based on the average contri-

bution of interconnections to security of supply during a peak load

event. This proposition assumes that the transmission rights would

be allocated free of charge, on a pro-rata basis. This solution would

have to be considered during the public consultation that RTE is pro-

posing to organise on explicit cross-border participation.

Other propositions were made. For instance, the French Com-

petition Authority has proposed in 2012 a solution involving the

allocation of cross-border capacity rights. This would be based

on market rules through an auction process. This type of system

could also be considered.

Lastly, implementing transitory solutions could lead to the imple-

mentation of a different approach at each border, as it might

take a lot of time to define a unique harmonised approach. This

also means that implicit and explicit participation of cross-border

capacities will coexist for a time. Implicit participation will remain

for market zones which are not covered by the explicit solution.

Implementing such a transitory solution would go beyond the

current legal framework of the French capacity market. RTE is

thus requesting a mandate of the Energy Minister on the possible

implementation of a transitory solution regarding explicit cross-

border participation in the French capacity market and on the

scope of the proposed public consultation.

212

10.1.1 Competence of Member States with regard to security of supply

Article 4 of the Treaty on the Functioning of the

European Union (TFEU) includes energy in the

list of areas of shared competence between the

Union and Member States. Article 194 of the TFEU

specifies how this competence is shared between

the Union and Member States when it comes to

10. COMPLIANCE WITH EUROPEAN PROVISIONS AND PRINCIPLES The creation of a capacity mechanism in France is provided for

in law 2010-1488 of 7 December 2010 reforming the organisa-

tion of the electricity market (NOME Law) and is a major evolu-

tion of the market design in France. This provision is embedded

in a broader review of the functioning of the regulated power

system and, especially, of market mechanisms. The main goal of

this revision program is to integrate demand-side response in all

market mechanisms, all timeframes279.

Imperfections observed in the energy market, together with

a substantial change in the physical needs of the French and

European power system, have raised questions about whether

the energy-only market alone can guarantee security of supply,

notably at a time when the energy transition is under way and

peak demand in France is increasing. Therefore, public interven-

tion to complement the existing market signals is justified.

Three fundamental choices about the capacity mechanism’s

market design were made in decree 2012-1405: (1) it would

be a market mechanism, (2) involving all capacities, and (3) all

market stakeholders would be held accountable for their contri-

butions to security of supply thanks to a decentralised archi-

tecture280. The capacity mechanism rules proposed by RTE put

these principles into practice. Moreover, while drafting its pro-

position of rules, RTE paid a special attention to the definition

of the required parameters to calculate suppliers’ obligation,

capacities’ certification or imbalance settlements. These

choices were made in order to design a capacity mechanism

that targets security of supply, is proportionate to this objective

and guarantees equal treatment for all stakeholders281. To this

end, RTE has prepared a roadmap and common principles for

allowing the explicit participation of cross-border capacities in

the mechanism along including a timetable to conduct a public

consultation on this issue before submitting concrete proposals

to the French Energy Minister and Regulatory Authority282.

All provisions included in French laws and in the rules proposed

by RTE regarding the capacity mechanism must be considered

within a European context. Indeed, though security of supply

is a component of Member States’ energy policies, there is, on

the one hand, significant interplay between Member States’

energy policies in an integrated market, and on the other hand,

a competence of the European Union in the area of energy .

In this report, RTE has sought to assess the French capacity

mechanism’s compatibility with the provisions of European

law. This chapter reviews the European legal framework within

which the capacity mechanism falls (§ 10.1) and demonstrates

that the market design adopted for the capacity mechanism

and developed in the rules proposed by RTE complies with the

general principles of necessity and proportionality set out in the

EU acquis and the European Commission’s recommendations

(§ 10.2).

10.1 The European legal framework governing State intervention to ensure security of supply

279See chapter 1 of this report

280See chapter 2 of this report

281See chapters 3 to 7 of this report

282See chapter 9 of this report

energy policies. This article indicates that Union policy on

energy shall aim to:

(a) Ensure the functioning of the energy market;

(b) Ensure security of energy supply in the Union;

(c) Promote energy efficiency and energy saving and the

development of new and renewable forms of energy; and

(d) Promote the interconnection of energy networks.

213

COMPLIANCE WITH EUROPEAN PROVISIONS AND PRINCIPLES / 10

283Article 3 of Directive 2005/89/EC

284[EC, 2013]

285Recital 10

286Considering different rulings in European case law, notably ECJ, 27 April. 1994, Case C-393/92, Municipality of Almelo ECR I, p. 1477, according to which electricity constitutes a good, it seems difficult to challenge that capacity can be considered a good, despite its potentially strategic characteristics (ECJ, 4 Oct. 1991, Case C-367/89, Richardt: ECR 1991, p. I-4621, point 16).

287[EC, 2013], [ACER, 2013]

288[EC, 2013]

This article also emphasises that measures taken by the Union

shall not affect a Member State’s right to determine its own

energy mix and the “general structure of its energy supply”. In

other words, security of supply is a matter of national compe-

tence and this competence must be exercised with due regard

to the principles and provisions of European law.

Secondary legislation takes this competence sharing into account

when defining the role of Member States in security of supply mat-

ters. Article 4 of Directive 2009/72/EC of 13 July 2009 concerning

common rules for the internal electricity market notably affirms that

“Member States shall ensure the monitoring of security of supply

issues”, and particularly “measures to cover peak demand and deal

with shortfalls of one or more suppliers”. Member States thus define

their own security of supply criterion and arrange to meet it by taking

the measures necessary to ensure a “stable investment climate”283.

The EU acquis thus does not prohibit state intervention to

ensure security of supply. The European Commission confirms

this in its Communication “Delivering the internal electricity

market and making the most of public intervention”:

Public intervention can be useful and effective to attain policy

objectives set at Union, regional, national or local level, but it must

be well designed and should be adapted to changes in market

functioning, technology and society that occur over time284.

Capacity mechanisms are explicitly named within the secondary

legislation among the tools for guaranteeing security of supply.

The possibility for Member States to introduce capacity mecha-

nisms is notably included in the measures provided for in Direc-

tive 2005/89/EC of the European Parliament and of the Council

of 18 January 2006 concerning measures to safeguard security

of electricity supply and infrastructure investment:

Measures which may be used to ensure that appropriate

levels of generation reserve capacity are maintained should

be market-based and non-discriminatory and could include

measures such as contractual guarantees and arrangements,

capacity options or capacity obligations. These measures

could also be supplemented by other non-discriminatory ins-

truments such as capacity payments285.

It was against this backdrop that the French Energy Code, in

articles L.335-1 et seq., called for an obligation to be imposed on

suppliers to contribute to security of electricity supply. The goal

was to supplement existing measures with a market mechanism

targeting security of supply.

10.1.2 Regulation of Member States’ competence through the provisions of the Treaty and secondary legislation

Though the EU acquis does not prohibit public inter-

vention to ensure security of supply, Member States’

competence is regulated by the provisions of the Treaty

and by secondary legislation, notably the provisions of

the Third Energy Package and Directive 2005/89/EC.

10.1.2.1 Provisions of the Treaty

The provisions relating to the free movement of goods –

articles 34 and 35 of the TFEU – impact the design of

the French capacity mechanism insofar as, in European

Court of Justice case law, electricity is considered a

good286. These articles respectively prohibit restrictions

on imports and exports along with any quantitative res-

trictions and measures having equivalent effect.

These provisions have a direct link with the capa-

city mechanism’s provisions on the participation of

cross-border capacities to security of supply in France. As dis-

cussed in chapter  9 of this report, the issue was raised during

the consultation of 2011, when the decree was being drafted,

and the various problematic points and difficulties identified led

to the decision that the contribution of cross-border capacities

to security of supply in France would be implicitly accounted for

the implementation of the capacity mechanism. The European

Commission and the Agency for the Cooperation of Energy

Regulators have also noted the difficulties related to the explicit

cross-border participation in capacity mechanisms287.

Implicit participation of cross-border capacities to security of

supply in France already ensures a high degree of economic

efficiency since it reduces capacity needs and prevents overca-

pacity. Chapter 9 also outlines the key principles to allow explicit

cross-border participation to the French capacity market, and

therefore to security of supply in France, along with milestones

RTE has proposed in the rules to pave the way towards this expli-

cit cross-border participation.

The European Commission considers this step-by-step approach as a

possible solution in its Staff Working Document “Generation Adequacy

in the internal electricity market - guidance on public interventions”:

[I]t may be necessary, as an interim step, for Member States to

calculate the contribution of imports to meeting the genera-

tion adequacy standards288.

214

10.1.2.2 Provisions of secondary legislation regarding

the energy sector

The provisions included in the Third Energy Package and Direc-

tive 2005/89/EC define the competence of Member States in

assessing their national level of security of supply and taking

safeguard measures in case of emergency situations.

Along these lines, article 7 of Directive 2005/89/EC289 provides

that Member States must prepare reports to:

Describe the overall adequacy of the electricity sys-

tem to supply current and projected demands for

electricity, comprising:

a) Operational network security;

b) The projected balance of supply and demand for

the next five-year period;

c) The prospects for security of electricity supply for

the period between year five and 15 years from the

date of the report; and

d) The investment intentions, for the next five or

more calendar years, of transmission system opera-

tors and those of any other party of which they are

aware, as regards the provision of cross-border inter-

connection capacity.

The law of 10 February 2000 had already tasked RTE

with the publication of adequacy reports in France290,

well before such adequacy assessments became

mandatory in Europe. These reports, called Adequacy

Forecast Reports, are prepared under the control of

public authorities291. The decree of 20  September

2006292 specified the framework, scope and study horizons for

these reports, in compliance with the provisions of Directive

2005/89/EC.

Article 11 of the decree of 20 September 2006 provides for an

adequacy criterion to be applied in France, which is an average

3 hours annual loss of load expectation:

The Multi-year Adequacy Forecast Report required by Article

1 of the present decree […] takes into account the annual

loss of load expectation used in previous adequacy forecast

reports, i.e. an average annual loss of load expectation due to

imbalances between electricity supply and demand of three

hours293.

Safeguard measures implemented by Member States in emer-

gency situations shall be taken respectfully of other EU provi-

sions. Notably article  3 Directive 2009/72/EC provides that

measures introduced by Member States must be “clearly defi-

ned, transparent, non-discriminatory and verifiable”. These

conditions are also provided for in article 2 of decree 2012-

1405, which specifies that the capacity mechanism rules must

be transparent and non-discriminatory.

The key provisions of the rules proposed by RTE were deve-

loped in chapters 3 to 6 of this report and have been designed

to implement a mechanism that is clearly defined and unders-

tandable by all market stakeholders.

The non-discrimination requirement relates not only to the dis-

tinction between French and cross-border capacities but also to

the application of non-discriminatory provisions to all capacity

mechanism participants. The participation of cross-border capa-

cities has been addressed both in the previous section of this

chapter and in chapter 9 of this report. As regards the second

point, all provisions proposed by RTE in the capacity mechanism

rules are respectful of the principle of non-discrimination, as it

was demonstrated in chapters 3 to 7 of this report. Two signi-

ficant examples are the non-discrimination between demand-

response, renewables and conventional generation capacities

289Directive 2005/89/EC of 18 January 2006 concerning measures to safeguard security of electricity supply and infrastructure investment.

290Article L.141-1 of the Energy Code.

291Several of these provisions were also included in the Energy Code, following amendments and repeals to the law of 10 February 2000, notably the NOME Act.

292Decree 2006-1170 of 20 September 2006 relating to multi-year adequacy forecast reports.

293Decree of 20 September 2006.

RTE considers that implicit participation of cross-border capacities already fairly recognises their contribution to security of supply in France. In a first step, it is thus a way to include the partici-pation of cross-border exchanges to security of supply in the French capacity market provisions, in compliance with the European Commission’s recent recommendations.

In order to allow the implementation of the target solution  – explicit participation of cross-border capacities  – a second step is required. To that extent, the proposed capacity mechanism rules provide for the organisation of a public consulta-tion in order to submit propositions regarding explicit participation of cross-border capacities in the capacity mechanism ten months after the publication of the rules.

The provisions of Directive 2005/89/EC concern-ing adequacy assessments are taken into account by RTE in its Adequacy Forecast Reports, which examine the electricity supply and demand bal-ance outlook for France over the medium and long terms.

215

COMPLIANCE WITH EUROPEAN PROVISIONS AND PRINCIPLES / 10

whether this measure constitutes an aid, and if so, if it is compa-

tible with the internal market, given its exclusive jurisdiction over

competition matters.

The framework for the energy sector is currently changing since

the European Commission is revising its guidelines on environ-

mental State aids  – the guidelines that serve as an analytical

framework for assessing whether State aids are compatible with

the internal market – and organised a public consultation on the

issue between 18 December 2013 and 14 February 2014. The

new draft guidelines include, for the first time, a section devoted

to energy State aids296.

The draft guidelines notably include a list of conditions under

which an exemption can be granted if a State adopts a capacity

mechanism that qualifies as State aid, i.e. if the five conditions

outlined above are met.

The European Commission has indicated that the final draft of

the guidelines on environmental and energy State aids should

be adopted in the first half of 2014.

10.1.3.2 Public service obligations provided

for in the Third Energy Package

The provisions of Directive 2009/72/EC authorise

Member States to impose public service obligations

on private undertakings in the energy sector.

Member States may impose on undertakings

operating in the electricity sector, in the gene-

ral economic interest, public service obligations

which may relate to security, including security

of supply, regularity, quality and price of supplies

and environmental protection, including energy

efficiency, energy from renewable sources and

climate protection297.

Supplementing the conditions laid down in article 3

of Directive 2009/72/EC, European Court of Justice

case law has specified the framework for evaluating

the compatibility of public service obligations with

the EU acquis, particularly in its Federutility298 and

Enel Produzione299 decisions, and has affirmed that

the legality of measures undertaken by Member

States should be evaluated based on necessity and

proportionality tests.

294[EC, 2013]

295See e.g., the definition adopted by the ECJ in Case C-280/00 Altmark Trans GmBH [2003] ECR I-7747 (ECJ, 24 July 2003).

296In their previous version, the guidelines only addressed the issue of State aid in the environmental sector.

297Article 3, paragraph 2 of Directive 2009/72/EC.

298Case C-265/08 Federutility and Others v Autorità per l’energia elettrica e il gas [2010] ECR I-3377 (ECJ Grand Chamber, 20 April 2010.

299Case C-242/10 ENEL Produzione SpA v Autorità per l’energia e il gas [2011] ECR I-0000 (ECJ, 21 December 2011).

in the certification process described in chapter 5 and the non-

discrimination between suppliers in the parameters defined

to calculate their capacity obligation, which are described in

chapter 4.

The consultation process on the capacity mechanism design

was transparent, as described in chapter  3. Stakeholders (incl.

the transmission system operator) are subject to transparency

obligations in the capacity mechanism and those provisions

have been described in chapter 7.

10.1.3 Legal forms of public intervention

Public interventions in the electricity market can take different

forms, the two most common of which are State aid and public

service obligations provided for in the Third Energy Package, as

the European Commission notes:

Public intervention at regional, national or local level can take

different forms. Examples include state aid to certain sectors

or companies in the form of grants or exemptions from taxes

and charges, the imposition of public service obligations, and

regulation through general measures294.

10.1.3.1 Environmental and energy State aid

State aids in the energy sector are governed by the general pro-

visions of article 107 of the TFEU relative to State aids and their

interpretation by the European Court of Justice. Paragraph 1 of

article 107 of the TFEU provides that forms of aid granted by

Member States that threaten to distort competition are incom-

patible with the internal market. Paragraphs 2 and 3 of that

article define the forms of aids that can be considered compa-

tible with the internal market.

State aid exists when all of the following five conditions are met:

there must be (i) a transfer of State resources (ii) conferring an

advantage (iii) on certain undertakings (iv) which distorts com-

petition and (v) which affects trade between Member States295.

When a State considers that these conditions are met, it must

notify the European Commission of the measure, in accordance

with article 108 of the TFEU, so the Commission can evaluate

RTE considers that all legal and regulatory pro-visions, and the regulatory framework govern-ing the implementation of the capacity mecha-nism, meet the conditions laid down in Directive 2009/72/EC.

216

France and Europe are changing significantly, and this could

increase the occurrence of market failures. The power system

will have to do more to help meet the ambitious energy transi-

tion objectives set by the European Union; it must therefore be

adapted to accommodate growing and massive penetration of

renewables. This makes it all the more important to have flexible

capacities, be they generation or demand-response resources,

to protect the electricity supply and demand balance.

Additional information must also be provided in response to the

specific framework proposed in the “Generation Adequacy in the

internal electricity market - guidance on public interventions”

Staff Working Document. According to European Commission

recommendations, the necessity of a capacity mechanism is

determined by whether a risk to security of supply has been

identified on the basis of generation adequacy assessments

that are “objective, facts based and comprehensive”301 and whe-

ther this risk persists after other measures positively impacting

the supply-demand balance have been introduced.

10.2.1.1 Assessment of generation adequacy in France

The time horizons considered for the capacity mechanism

are such that the methodology and conclusions of the sec-

tion of RTE’s Adequacy Forecast Reports devoted to the five-

year medium term must be considered. A description of RTE’s

methodology can be found in the 2012 Adequacy Forecast

Report or the 2013 Adequacy Forecast Report update.

10.2.1.1.1  Transparency and stakeholder consultation 

The Adequacy Forecast Report is based on hypotheses about

future trends in electricity supply and demand that RTE

10.2 Compliance with the principles of necessity and proportionality

It is not RTE’s role to determine the legal qualification of the capacity mechanism. It could be noted, however, that the design adopted for the capacity mechanism can be assessed with regard to the framework for public service obli-gations. The obligation is imposed upon suppliers to help meet the security of supply target set by public authorities by having sufficient capacity to ensure electricity supply to their final customers. Generators and demand-response operators are required to participate in the mechanism and ensure that it functions properly by certifying all of their generation capacities. The commitments undertaken during the certification process to make their capacities avail-able ensure that they will effectively contribute to security of supply during peak demand periods.

Regardless of how the capacity mechanism is legally qualified, the legality of the public intervention is notably eval-uated based on necessity and proportionality tests. These principles therefore need to be respected when imple-menting the capacity mechanism.

Compliance with the principles of necessity and proportionality

should be assessed in the light of the adequacy between the

given public intervention and the objective of public interest it

pursues. In this instance, ensuring security of supply is the aim of

public interest pursued by French public authorities300.

It is important to emphasise that the European Commission

recently expanded its analytical framework for examining public

intervention to ensure security of supply through the Staff Wor-

king Document “Generation Adequacy in the internal electricity

market - guidance on public interventions” accompanying its

Communication “Delivering the internal electricity market and

making the most of public intervention”. This Staff Working

Document features a checklist regarding (1) the

assessment of needs, (2) the adoption of structu-

ral measures to improve the functioning of energy

markets, and (3) design choices compatible with the

internal market.

The facts presented by RTE regarding the necessity

and proportionality of the mechanism thus refer pri-

marily to the framework proposed by the European

Commission in November 2013.

10.2.1 Principle of necessity

Chapter  1 of this report discusses various points

that justify public intervention to ensure security

of supply. Indeed, empirical observation points to a

number of imperfections in current energy markets.

In addition, the physical needs of power systems in

300Because the principle of subsidiarity applies, national authorities have, under EU case-law, discretionary power to define what they consider to be services of general economic interest and “to provide, to commission and to fund such services”, “in compliance with the Treaties”, as specified in article 14 of the TFEU. It is thus within the remit of Member States, under the aegis of national judges, to determine what is in the general interest, in compliance with the qualifications specified in EU law.

301[EC, 2013a]

302[EC, 2013a]

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COMPLIANCEWITHEUROPEANPROVISIONSANDPRINCIPLES / 10

European Commission recommendations on the introduction of capacity mechanisms302

Continuation l

JUSTIFICATION OF INTERVENTION

Assessment of generation gap

(1) Is the capacity gap clearly identifi ed and does this distin-

guish between need for fl exible capacity at all times of year

and requirements at seasonal peaks? Has a clearly justifi ed

value of lost load been used to estimate the cost of supply

interruptions?

(2) Has the assessment appropriately included the expected

impact of EU energy and climate policies on electricity infra-

structure, supply and demand?

(3) Does the security of supply and generation adequacy

assessment take the internal electricity market into

account; is it consistent with the ENTSO-E methodology

and the existing and forecasted interconnector capacity?

(4) Does the assessment explain interactions with assess-

ments in neighbouring Member States and has it been

coordinated with them?

(5) Does the assessment include reliable data on wind and

solar, including in neighbouring systems, and analyse the

amount as well as the quality of generation capacity needed

to back up those variable sources of generation in the system?

(6) Is the potential for demand side management and a realistic

time horizon for it to materialize integrated into the analysis?

(7) Does the assessment base the assessment of gene-

ration plant retirements on projected economic conditions,

electricity market outcomes and the operating costs of that

generation plant?

(8) Has the assessment been consulted on widely with all

stakeholders, including system users?

Causes of generation adequacy concerns

(9) Has retail price regulation (with the exception of social

prices for vulnerable customers) been removed?

(10) Have wholesale price regulation and bidding restric-

tions been removed?

(11) Have renewable support mechanisms been reviewed in

line with the Guidance on renewable support before inter-

vening on generation adequacy grounds.

(12) Has the impact of existing support schemes for fossil

and nuclear generation on incentives for investments in

additional generation capacity or maintenance/refurbish-

ment of existing generation capacity been assessed?

(13) Are eff ective intraday, balancing and ancillary service’s

markets put in place and are any remaining obstacles, in

those markets removed? Have any implicit price caps from

the operation of balancing markets been removed?

(14) Have structural solutions been undertaken to address

problems of market concentration?

Options other than support for capacity

(15) Have the necessary steps been taken to unlock the

potential of demand side response, in particular has Article

15(8) of Directive 2012/27/EU on Energy Effi ciency been

implemented and do smart meter roll out plans include the

full benefi t of demand side participation in terms of genera-

tion adequacy?

(16) Have the benefi ts of expanded interconnection capac-

ity been expanded, in particular towards neighbouring

countries with surplus electricity generation or a comple-

mentary energy mix been fully taken into account.

(17) Have the impacts of the intervention on the achieve-

ment of adopted climate and energy targets been assessed

holistically, and is lock-in of high carbon generation capacity

and stranded investments avoided?

218

Continuation j

CHOICE OF MECHANISM

Choice and design of intervention

(1) Has the eff ectiveness of a strategic reserve been examined?

(2) Has the potential for a credibly one-off tendering proce-

dure to address the identifi ed capacity gap been examined?

(3) Does the chosen mechanism ensure that identifi ed ade-

quacy gap will be fi lled while avoiding risks of overcompen-

sation (unlikely with payments payments)?

Recommendations to avoid distortion of internal

electricity market

(4) Is the chosen mechanism open to demand side participation?

(5) Is the mechanism to ensure generation adequacy consist-

ent with the long term decarbonisation of the power sector?

(6) Is the chosen mechanism (other than a tendering

scheme) open to existing and new generation?

(7) Are conditions for participation in the mechanism based

on technical performance and not technology type?

(8) Does the chosen mechanism deliver a price of zero

when there is already suffi cient capacity available?

(9) Has a framework for the phase out of the mechanism in

line with a roadmap for addressing underlying market and

regulatory failures been developed

(10) Does the lead time for a capacity mechanism correspond to

the time needed to realise new investments, that is 2-4 years?

(11) Is the mechanism open to all capacity which can

eff ectively contribute to meeting the required generation

adequacy standard, including from other Member States?

Insofar as imports are accounted only on an implicit basis, is

a mechanism established to calculate this benefi t and allo-

cate funds to this value for the development of additional

interconnection capacity?

(12) Is it ensured that there are no export charges or proce-

dures to reserve electricity for the domestic market?

(13) Have all barriers to the equal treatment of national and

cross border contracts been removed?

(14) Are there no price caps or bidding restrictions as a

result of the chosen mechanisms?

(15) Is it ensured that the operation of the chosen mecha-

nism does not lead to ineffi cient production by operators?

(16) Is it ensured that the capacity mechanism does not

adversely aff ect the operation of market coupling or cross

border intraday trading?

(17) Does the chosen mechanism allocate the costs to con-

sumers on a non-discriminatory basis, taking into account

their consumption patterns and without reductions for par-

ticular customer segments?

calculates as realistically as possible. RTE consults power sys-

tem stakeholders on the hypotheses used in the Adequacy

Forecast Report.

In line with RTE’s commitment to transparency,

the hypotheses adopted in the 2012 Adequacy

Forecast Report were submitted to a collegiate

consultation process with the “Network Outlook

Committee” (Commission Perspectives du Réseau)

of the Transmission System Users’ Committee

(Comité des utilisateurs du Réseau de Transport de

l’Electricité – CURTE)303.

The assumptions incorporated into models of the Western Euro-

pean power system are based on information provided to RTE

by diff erent power system actors during bilateral exchanges304;

on work done by ENTSO-E; on information made public by

stakeholders in the European power market (generators, sup-

pliers, system operators, electricity exchanges); and on research

conducted by various energy market research consultancies or

government agencies. RTE also met with diff erent stakeholders

in the European power system (transmission system operators,

regulators, etc.), through working groups (ENTSO-E) and bilate-

ral meetings, to exchange ideas about changes in the methodo-

logies used in its Adequacy Forecast Reports.

303[RTE, 2012a]

304RTE guarantees the confi dentiality of all information of a commercially sensitive nature to which it is given access.

219

COMPLIANCE WITH EUROPEAN PROVISIONS AND PRINCIPLES / 10

10.2.1.1.2  Demand forecasts

Demand forecasts are constructed in two phases: 1) forecasts

established for annual energy demand for each year of the study

horizon, and (2) forecasts established for power demand on an

hourly basis. Each of these phases includes a retrospective analy-

sis of past years, making adjustments to years used as reference

periods for simulations, as well as a forward-looking study.

Four demand scenarios were created for the medium term to

represent the spectrum of possible outcomes: “Baseline”, “High”,

“Low” and “Stronger DSM”. The main assumptions differentiating

these scenarios are outlined below.

The “Baseline” scenario integrates the central assumptions

for each driver of demand.

The “High” scenario incorporates all assumptions implying an

increase in demand. […]

The “Stronger DSM” scenario assumes the same economic envi-

ronment as the “Baseline” scenario but calls for an acceleration

of demand-side energy management efforts in general. […]

The “Low” scenario incorporates assumptions leading to

a decrease in demand, including a relatively unfavourable

economic situation and a weak demographic

variant305.

The key factors differentiating the scenarios are shown in the

table below.

Economic growth also has a significant impact on electricity

demand in other European countries. To be able to build projec-

tions of European demand while maintaining a consistent fra-

mework, GDP assumptions have also been established for these

countries using a similar approach as the French one.

All scenarios assume that energy efficiency will steadily improme,

helping to keep electricity demand growth in check, notably

through the diffusion of technological progress and the imple-

mentation of laws or regulations favouring the development of

energy efficiency, including Directive 2009/125/EC of 21 Octo-

ber 2009 creating a framework for defining eco-design require-

ments applicable to energy-related products.

The Adequacy Forecast Report is prepared using demand data

series for France as well as for European countries (at a Western

European scale).

305[RTE, 2012a]RTE’s Adequacy Forecast Reports fully comply

with the European Commission’s recommenda-tions regarding transparency and stakeholder consultation.

Table 6 – Main assumptions used in demand scenarios

Demand scenario “Baseline” “High” “Stronger DSM” “Low”

Key assumptions Central Higher overall demand

Increased energy efficiency

Lower overall demand

GDP Central High Central Low

Energy efficiency Central Lesser effect Greater effect Central

Demographic Central Haute Central Low

Electricity price CentralFavourable to rollout of new electricity-based

solutionsCentral

Unfavourable to rollout of new electricity-based

solutions

The demand forecasts produced by RTE for the Adequacy Forecast Report comply with the Euro-pean Commission’s recommendations regarding their consideration of the impact of EU energy and climate policy, particularly energy efficiency tar-gets. A steady improvement in energy efficiency is highlighted in all scenarios.

220

10.2.1.1.3  Supply forecasts

Medium-term supply trends are presented by technology in the

Adequacy Forecast Report: (1) centralised fossil-fired capacity, (2)

nuclear power, (3) embedded thermal generation, (4) renewable

energy sources and (5) generation capacity outside France.

For centralised fossil-fired generation, and particularly combined-

cycle gas plants, the Adequacy Forecast Report takes into account

official announcements by generators, notably the mothballing of

one unit (between 2014 and 2016) and the shutdown of several

others in the summer of 2013, with these same units taken offline

every summer in all the years considered in the report through

2018. It is assumed that no new capacity will be commissioned

outside France over the period considered in the report.

As regards nuclear power in France, it is assumed that the two

reactors Fessenheim will be out of service at the end of 2016,

reducing installed capacity by 1,760  MW, per the announce-

ments made by public authorities.

Onshore wind capacity development should resume in 2014,

thanks to several policy signals306, and expansion in the coming

years is expected to at least match that observed in the past two

years, implying the addition of around 800  MW a year, which

would take wind power capacity to more than 12 GW in 2018.

The Adequacy Forecast Report assumes that photovoltaic capa-

city will increase by 800 MW a year, to factor in uncertainty about

the industry’s development (particularly the effects of the mea-

sures introduced by the French government in 2013 to encou-

rage its expansion). Based on this growth estimate, photovoltaic

capacity should reach 8.3 GW in 2018.

As regards demand response, it is assumed in the Adequacy

Forecast Report that capacity will be flat over the medium term,

stabilising at a level slightly above that observed

today, with a decrease in tariff-based demand res-

ponse being offset by the increased participation

of demand response in market mechanisms. The

forecast could be revised upward depending on the

effects the framework laid down in law 2013-312

(Brottes Act) on preparing for the transition to a low-

energy system will have on the demand response

potential, and on the reintroduction of demand res-

ponse tariffs announced by the Government.

Regarding generation capacity outside France,

assumptions for all 11  countries modelled (Spain,

Portugal, United Kingdom, Ireland, Belgium, Luxembourg,

Netherlands, Germany, Switzerland, Austria and Italy) are taken

into account.

The development of the electricity transmission system is also

factored into the assumptions307.

10.2.1.1.4  Probabilistic approach

Future supply and demand forecasts thus produced are com-

pared by simulating the operations of the Western European

power market on an hourly basis over a full year.

For both Europe and France, around a hundred demand

series have been produced based on temperature datasets

produced in cooperation with Météo France for Europe, to

assess the impact of cold spells and heat waves on the Euro-

pean power system.

[…]

With regard to generation capacity, the methodology applied

to foreign countries for the medium term is similar to that

used for France.

[…]

Generally speaking, to ensure the balance between supply

and demand, generation facilities are used in ascending order

of their marginal cost of production (the merit order), until

demand is met. Since the late 1990s, when instruments were

306Examples: Adoption of Regional Climate, Air and Energy Plans, changes in the law to facilitate wind turbine installation.

307Over the medium term, two noteworthy changes will affect interconnections to France, both of which are scheduled for 2015: the strengthening of exchange capacity with Spain […] and the strengthening of the French network in the Alps.

The supply forecasts produced by RTE within the framework of the Adequacy Forecast Report comply with the European Commission’s recom-mendations on taking into account EU energy and climate policy, particularly the greenhouse gas emissions reduction target, by factoring in the effects the EU directives designed to help achieve this target will have over the period under review and the renewable energy development target.

Regarding renewable energy development, the trend still points to a more robust expansion of these resources than other technologies over the period under review. Demand management is also taken into account through demand response capacity, including within the framework of mar-ket mechanisms.

Regarding the closure of generation units, RTE’s assumptions take into account the shutdowns officially announced by generators, which have the most up-to-date information about their capacities and the economic outlook for them. The internal market is factored into supply forecasts by including capacity assumptions for 11 Western European countries.

221

COMPLIANCE WITH EUROPEAN PROVISIONS AND PRINCIPLES / 10

developed to allow comparisons of supply between different

countries, this merit order has been seen from a European

standpoint, meaning that at any given time, the units with

the lowest production costs in Europe can be called upon

to meet demand expressed in Europe as a whole. The merit

order is respected provided that exchange volumes do not

exceed transmission capacity between countries or regions

within a same country308.

The simulations take into account the main contingencies that

can threaten security of supply, including weather conditions

and especially outdoor temperatures, unscheduled unavailabi-

lity of thermal generation capacities, water resources and wind

and photovoltaic power production. The spatial and temporal

correlations of a given natural hazard are taken into account at

the European scale.

A set of temporal series, loads on the demand side and avai-

lable capacity of units generating supply reflecting various

possible outcomes are created for each of the phenomena

considered. These series are then combined in sufficient

number (1,000 for each scenario) to give statistically signifi-

cant results in shortfall (risk of demand not being met due to

a lack of generation) and annual energy balances (output of

different units and exchanges with neighbouring systems)309.

The supply-demand balance is assessed by comparing each

demand scenario with the supply scenarios. Moreover, as

required by the decree of 20  September 2006, the “Baseline”

demand scenario is compared to supply forecasts with and with-

out exchanges to identify the contribution interconnections

make to covering the shortfall risk in France.

In the zero exchange balance analysis required by the decree,

the shortfall criterion is exceeded under the “Baseline” scenario

over the duration of the period considered (including today),

illustrating how crucial electricity imports are to security of supply

in France. The capacity that would be needed to meet the crite-

rion without interconnections exceeds 6 GW starting in 2016310.

10.2.1.1.5  Compatibility with ENTSO-E’s methodology

RTE’s Adequacy Forecast Report is compatible with ENTSO-E’s

“Scenario Outlook and Adequacy Forecast”311. However, the

results vary due to differences between assumptions applied to

countries other than France and the fact that the probabilistic

simulations used in the Adequacy Forecast Report are more ela-

borate that the deterministic calculations in the “Scenario Out-

look and Adequacy Forecast”.

ENTSO-E has publicly announced that it plans to propose

changes to the methodology used in the “Scenario Outlook

and Adequacy Forecast” and participate in their implementa-

tion, notably to generate studies at a European scale based on

the same probabilistic approach as the one RTE uses in the

Adequacy Forecast Reports for France.

ENTSO-E is already committed to examining possible changes

with particular regard to treatment of RES-E resources. These

range from small changes to existing methodologies to fully

implementing probabilistic adequacy assessments in the

short and long term. However any changes need to consider

the conflicting objectives of depth of analysis with the asso-

ciated need for increasing requirements against the timely

production of useful outlook reports.

[…]

Nevertheless ENTSO-E and its member TSOs are actively

developing the tools and techniques to address these issues

over time.

[…]

It would be highly desirable if stakeholders (EC,

ACER, market participants) and ENTSO-E could

further discuss and agree on a high-level vision

on the expected scope and content of the ade-

quacy reports. Thereafter appropriate and neces-

sary adjustments in methodology and structure

of the report could be made312.

308[RTE, 2012a]

309[RTE, 2012a]

310[RTE, 2012a]

311[ENTSO-E, 2013]

312[ENTSO-E, 2013]

infrastructure; recommendations on taking the internal market into account are complied with since the simulations are carried out for the West-ern European power system. Moreover, the com-parison of simulation results with and without exchanges highlights the role interconnections play in ensuring security of supply in France. As regards the inclusion of variable sources, the simulations respect the spatial and temporal cor-relations of individual contingencies (including for wind power) at the European level.

The probabilistic approach used by RTE to assess the supply-demand balance complies with the European Commission’s recommendations on taking into account European energy and cli-mate policy (20-20-20  objectives) and upholding the provisions of Regulation 347/2013 by factor-ing in the development of new interconnection

222

10.2.1.1.6  Conclusions regarding generation adequacy 

assessments 

The European Commission’s first consideration in evaluating the

need for public intervention to safeguard security of supply is

that a facts-based, objective and comprehensive assessment

of adequacy and security of supply has been conducted. RTE’s

Adequacy Forecast Report is used to assess the electricity sup-

ply and demand balance in France, and the methodology used

to carry out this assessment complies with the European Com-

mission’s recommendations:

> Demand forecasts take into account European energy and cli-

mate policies (particularly with regard to demand-response);

> Supply forecasts take the internal market into account

through the integration of hypotheses regarding the genera-

tion fleet of other European countries;

> Simulations are carried out using a probabilistic approach with

a careful modelling of contingencies and their corre-

lations (particularly for variable sources);

> All requirements in terms of transparency and

stakeholder consultation are met.

The results presented in the most recent update of

the Adequacy Forecast Report (2013), outlined in

chapter  1 of this report, show that safety margins

vis-à-vis the security of supply criterion will gradually

shrink and then disappear in 2017. This suggests

that security of supply in France will have to be care-

fully monitored and will be at risk in 2017, particu-

larly if a cold spell occurs.

10.2.1.2 Other measures to improve the supply-

demand balance

On the basis of this comprehensive assessment, the Euro-

pean Commission recommends a series of measures that can

improve the supply-demand balance and help resolve adequacy

gap situations.

Questions about retail price regulation313, renewable support

mechanisms and support schemes for fossil and nuclear gene-

ration do not pertain to areas in which RTE is directly involved.

These issues are therefore not addressed in this report.

Lastly, the issue of whether the capacity mechanism will lock in

high-carbon generation capacity, which would be counter to EU

energy and climate objectives, is addressed in chapter 2 of this

report, where the main architectural choices proposed for the

capacity mechanism are outlined.

10.2.1.2.1  Measures to improve the functioning of the 

wholesale market and intraday, balancing and system 

services markets 

10.2.1.2.1.1 Wholesale market

The European Commission has voiced concerns that energy

price caps could hinder the formation of prices that send ade-

quate signals to market participants. In the North Western

Europe day-ahead market coupling, prices transmitted through

bids by market participants in the French market have ranged

between -€500/MWh and €3,000/MWh since NWE price cou-

pling was launched on 4  February 2014. Price caps were har-

monised across the region in order to reduce constraints in the

market. As the European Commission notes in its “Generation

Adequacy in the internal electricity market” guidelines, these

limits are among the highest in Europe.

It should also be noted that these price limits are not defined

through laws or regulations and can thus be periodically revised.

Wholesale market participants can trade on the EPEX SPOT mar-

ket but also over the counter or through a broker. There is no

regulated tariff governing prices on the wholesale market. The

ARENH mechanism, a specific regulation governing the ability

for alternative suppliers to source electricity directly from EDF

at a regulated price, was introduced to open the French supply

market to competition under the control of the European Com-

mission. Since 1 July 2011, in accordance with the provisions of

the NOME Act, suppliers have been able to exercise their right

to regulated access to historical nuclear electricity (ARENH) by

313The introduction of the market mechanisms presented in chapters 1 and 10 of this report, e.g. the NEBEF mechanism, allows demand response to participate in electricity markets over all time horizons and thus help make the load curve more flexible, even when regulated tariffs are applied. Moreover, the French Government recently committed to reintroducing demand response tariffs to create incentives to reduce consumption.

As part of the work being done by the Electricity Coordination Group at the European scale and by the Pentalateral Forum for Western Europe, Mem-ber States and the European Commission have asked transmission system operators to adapt the methodologies used by ENTSO-E to enhance the quality of its European reports. ENTSO-E has also created a workgroup focusing on adapting the methodologies used in the Scenario Outlook and Adequacy Forecast, one priority of which will be to propose a harmonised probabilistic methodology for adequacy assessments.

With this in mind, RTE considers that any discrep-ancies between the Adequacy Forecast Report and ENTSO-E’s Scenario Outlook and Adequacy Forecast will narrow as ENTSO-E’s methodologies are updated, and that current differences are not a hindrance. Should hypotheses continue to differ over the long term, it will be for reasons such as time gaps between studies.

223

COMPLIANCE WITH EUROPEAN PROVISIONS AND PRINCIPLES / 10

buying electricity directly from EDF at a regulated price and in

quantities defined by the regulator. This measure was intended

to stimulate competition in the French wholesale market by

allowing new entrants to make competitive offers.

10.2.1.2.1.2 Intraday market

Price limits are higher on the intraday market than on the day-

ahead market, ranging between -€9,999/MWh and €9,999/MWh.

Mechanisms are already in place to enable the integration of

the French intraday market at the European level. For instance,

on 26 June 2013, intraday market mechanisms between France,

Germany, Austria and Switzerland were launched in order to allow

market participants in these countries, EPEX SPOT members, to

engage in intraday cross-border trades.

This mechanism will be an essential building block in fostering

migration to the intraday solution called for in the European tar-

get model.

10.2.1.2.1.3 Balancing and ancillary services markets

Bids submitted to the balancing mechanism are not subject to

price limits. Since the mechanism was created in 2003, it has been

possible for demand response bids to participate in the same way

as bids from generators. Cross-border bids have been possible

with Switzerland since 2003 and with Germany since 2005.

RTE has also participated in the creation of cross-border balan-

cing mechanisms to allow cross-border trading, including after

the intraday cut-off. For instance, the BALIT mechanism (BALan-

cing Inter TSO) allows transmission system operators RTE and

National Grid to exchange balancing energy (beyond requi-

red margins). BALIT enhances competition on the balancing

mechanism by bringing new market participants into national

mechanisms, thereby boosting economic efficiency. The

mechanism is a precursor for the development of cross-border

balancing energy trading at the European level, in keeping with

the provisions of the Electricity Balancing Network Code. RTE is

also taking part in the TERRE project in partnership with National

Grid, REN and Terna314.

Where frequency containment reserves and frequency resto-

ration reserves (ancillary services)are concerned, article L. 321-

11 of the Energy Code charges RTE with “ensuring that ancillary

services for the operation of the grid are available and effecti-

vely provided” and with setting terms of participation and rules

for calculating the remuneration of system services, subject to

approval by CRE.

To this end, RTE conducted a consultation through

a Transmission System Users’ Committee (CURTE)

workgroup in 2013 to consider the design of

an organised secondary market for Frequency

Containment Reserve and automated Frequency

Restoration Reserve and propose rules to govern

the participation of demand response in system

services315.

The idea of an organised secondary market to

help optimise the power system emerged from

the consultation with market stakeholders. Par-

ticipation in this market should be optional and

standard products would have to be defined to

facilitate trading initially. It was on the basis of this

consultation that RTE introduced technical and

legal prerequisites into the system service rules316 to make the

creation of a secondary Frequency Containment Reserve and

automated Frequency Restoration Reserve market possible.

All of RTE’s proposals were approved by CRE in its deliberation

of 28 November 2013 approving the system service rules. The

new rules have superseded system service contracts since

1 January 2014. RTE will specify procedures for notifying reserve

exchanges and financial guarantees by 1 January 2015.

10.2.1.2.2  Participation of demand-response 

in electricity markets 

The sections below elaborate on the summary data presented in

chapter 1 of this report about the various mechanisms in place

or being developed to allow the demand side to participate in

the French electricity market over different time horizons.

314The TERRE project is designed to allow the trading of replacement reserves between France, Italy, Portugal and Great Britain and was selected as a pilot project for the implementation of the Electricity Balancing Network Code.

315See section 10.2.1.2.2.1.

316In particular, the role of the “reserve manager” was introduced and a system was created for notifying exchanges of reserves along with a related financial guarantee system.

Changes are being effected in many areas to add new functionalities to markets, only one of which is the creation of an organised secondary market for ancillary services.

Implementation of the capacity mechanism will not prevent improvements from being made to the existing market architecture.

France continues to be increase its integration into the European electricity market and is playing a pioneering role through the initiatives in which It is actively involved (NWE market coupling, flow-based capacity allocation in the CWE region, inte-gration of French, Swiss, German and Austrian intraday markets, BALIT mechanism, etc.)

224

10.2.1.2.2.1 Participation of demand-response in

the balancing mechanism, reserves procurement

and ancillary services

The balancing mechanism gives RTE real-time access to upward

and downward balancing reserves so it can ensure equilibrium

in the power system.

Since it was created in 2003, the balancing mechanism has

allowed the activation of demand response by industrial users

connected to the public transmission system. In 2007, an expe-

riment was launched to enable the participation of distributed

demand response as well.

The experiment RTE is conducting in Brittany will give market partici-

pants additional opportunities to participate in the balancing mecha-

nism and contribute to the supply-demand balance. It makes it pos-

sible to offer local generation connected to the public distribution grid

or demand response that can be activated on the balancing mecha-

nism, subject to minimum aggregate power of 1 MW.

Article L.321-11 of the Energy Code authorises RTE to enter into

contracts with generators and suppliers for replacement reserves

that can be activated on the balancing mechanism. These

contracts are established through “competitive, non-discriminatory

and transparent procedures”. Since 2008, it has been possible to

select demand response for rapid replacement reserve contracts.

The market share of demand response has been growing steadily

ever since, thanks to the product segmentation proposed by RTE.

Lastly, specific mechanisms have been introduced to allow

demand response to participate in short-term market

mechanisms.

In accordance with article 1 of the order of 10 December 2012

applying article L. 321-19 of the Energy Code, RTE “enters every

year into one-year interruptibility contracts with consumption

sites connected to the transmission system with ins-

tant interruptibility profiles […]”.

Article 7 of the NOME law calls for the organisation of

“a call for tenders (…) to secure additional demand-

response capacity for a period of three years”. In

other words, it has been possible for demand res-

ponse capacities to participate in specific tenders

since 2011. The tender organised in 2012 allowed at

least 400 MW of capacity that can be activated until

September 2013, along with at least 200  MW that

can be activated until 2015.

The consultation process organised in 2013317 led RTE to pro-

pose an experimental phase during which extraction sites

will be allowed to provide ancillary services (FCR and aFRR) in

limited quantities starting on 1  July 2014. Extraction sites’ abi-

lity to provide frequency containment or restoration reserves

will be rewarded indirectly: operators can sell these reserves to

obligated generators, setting their own price. Transactions will

be conducted over the counter and then, if applicable, through

an organised secondary market. The methods used to certify

and verify the performances of these capacities will be defined

in the first half of 2014, based on a consultation with market

stakeholders.

The CRE deliberation of 28 November 2013 approving the ancil-

lary services rules calls for RTE to submit to CRE draft ancillary

services rules for allowing the participation of extraction sites,

based on the outcome of the experiment conducted in 2014, by

1 September 2015 at the latest.

10.2.1.2.2.2 Explicit participation of demand-response

in the energy market

Demand-response can be a competitive alternative to electricity

generation. It thus makes economic sense to adopt provisions

that allow demand response to participate in electricity mar-

kets, i.e. to be activated (on the day-ahead or intraday market)

in the same way as available generation capacity to ensure that

forecast demand is covered (and not just to offset residential

imbalances).

Demand-response can be rewarded “implicitly” via private opti-

misation within a supply portfolio, for instance through dyna-

mic pricing318, or “explicitly”, as provided for in the Brottes law.

Thanks to the NEBEF mechanism introduced on January, 1st

2014, demand-side operators can capitalise on the flexibility of

consumption sites to fully leverage short-term optimisation pos-

sibilities, since a site that reduces load benefits either directly or

through a demand-side operator from any differential between

market and supply prices over the period. In sum, it is a tool for

enhancing the flexibility of the load curve including when sites

are on regulated tariffs or have entered into fixed-price supply

contracts through the market.

The NEBEF experimental rules notably specify the conditions

and terms under which a demand-side operator can sell a block

of energy resulting from explicit load reduction on electricity

markets, and how the block must be perfectly fungible with

other energy blocks traded on markets.

317See section 10.2.1.2.1.3.

318For instance peak/off-peak hours (allowing water heaters to be switched on at off-peak times). This implicit valuation of the storage potential is emphasised by the European Commission in the Staff Working Document, “Incorporating demand side flexibility, in particular demand response, in electricity markets“.

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COMPLIANCE WITH EUROPEAN PROVISIONS AND PRINCIPLES / 10

The rules are designed to create a level playing field for dif-

ferent stakeholders in the demand response market, suppliers,

demand-side operators and consumers. With this in mind, the

proposed design is based on:

> A new regulation framework, based on competitive assess-

ment319, especially regarding the financial relations between

demand-side operators and suppliers320;

> The nomination of a third party (RTE) as the “independent

third party” and intermediary between suppliers and demand-

side operators, charged with protecting the confidentiality of

data transferred, handling the certification process and the

control of data used and of the physical reality of the demand-

response activated.

10.2.1.2.3  Development of interconnections 

The points discussed below are intended to complement chap-

ter 1 of this report, which notably highlighted the fact that five

of the projects RTE is conducting with European partners have

been identified as Projects of Common Interest as defined in

Regulation 347/2013321, and briefly describe the cross-border

projects included in RTE’sten-year plan of 2012.

RTE and its partners are planning to develop new intercon-

nection capacity with the British Isles, Italy, Spain, Belgium,

Luxembourg and Germany, which together could add 10  GW

of exchange capacity between France and partner countries by

2025. RTE estimates that it will invest some 1.5 billion euros a

year in these projects over the next ten years322.

RTE’s ten-year plan presents a number of intercon-

nection projects:

> France/England: The IFA 2 project under way

involves a 1,000  MW, approximately 250  km link

that could be operational before 2020. It will

connect the Normandy coast with southern

England at the Isle of Wight. The “France-Alder-

ney-Britain” (FAB) project, intended to harness

the tidal power potential off the coast of Auri-

gny, includes the study of a new interconnection

between France and the United Kingdom with

a capacity of between 1,000  MW and 1,400  MW

that could be in place in 2022.

> France/Ireland: RTE and the Irish TSO, Eirgrid,

are studying the feasibility of a new link between

France and Ireland with a maximum capacity of

700 MW.

> INELFE (Interconnexion Électrique France-

Espagne, a mixed-capital corporation shared

by REE and RTE) is leading a project to build an

underground interconnection by 2015 between

France and Spain, in the Eastern Pyrenees, to lift

exchange capacity between the countries to 2,800 MW. Joints

studies are also under way to study the possibility of building

a direct current line running under the sea between Bilbao

and Aquitaine, through the Gulf of Gascony, which would take

exchange capacity between the countries to 4,000  MW in

2020.

> France/Italy: The Savoie-Piemont project conducted with the

Italian system operator will ultimately boost exchange capa-

city with Italy by 500 MW.

> France/Belgium: RTE and Elia are looking into strengthening

interconnections to increase exchange capacity by about

1,000 MW.

> France/Germany: RTE is working with Amprion and TransnetBW

on ways to increase interconnection capacity between the

countries, notably by strengthening existing interconnectors.

> Through ENTSO-E, RTE is working with Swissgrid to study the

feasibility of increasing interconnection capacity by streng-

thening existing interconnectors.

319Decision 13-A-25 of 20 December 2013 on demand response in the electricity sector – paragraphs 204 – 217 on methods for calculating payment by demand-side operator to the supplier of the site that reduces demand.

320Decision 13-A-25 of 20 December 2013 on demand response in the electricity sector – paragraphs 177 – 185 on the absence of agreement from the electricity supplier for the demand-side operator to activate demand response at sites supplied by this supplier.

321Regulation 347/2013 on guidelines for energy infrastructure.

322[RTE, 2012 ten-year plan 2012]

The electricity market design in France is cur-rently undergoing structural changes to allow the participation of demand-response in all mar-kets, in keeping with the European Commission’s recommendations.

In this regard, the NEBEF experimental rules rep-resent a big step forward for electricity market design in France and Europe and enable demand-response to be an additional competitive tool to balance the system in an optimal way.

The ability for demand-response to participate in the balancing mechanism and contracts for the provision of system services and restoration reserves is another crucial building block for inte-grating the demand-side into markets. Specific mechanisms are also in place for demand response (demand-response and interruptibility auctions).

The launch in 2014 of an experiment testing the participation of demand-response in ancillary ser-vices is the third pillar of the new market design.

The interconnection projects presented in RTE’s ten-year plan are proof that the introduction of the capacity mechanism will not interfere with the development of interconnections between France and neighbouring countries.

226

10.2.1.2.4  Conclusions about the adoption of other 

measures to improve the supply-demand balance

The European Commission only considers public intervention

in the form of capacity mechanisms necessary when structu-

ral measures have been taken to improve the functioning and

integration of energy markets. Such measures have a favourable

impact on the price signals generated by the market and its abi-

lity to assign the right value to energy.

The measures discussed in chapter  1 and the present chap-

ter  of this report show that the actions undertaken in French

electricity markets comply with the European Commission’s

recommendations.

These measures promote the integration of markets and

improve their functioning. In this regard, they help correct

market imperfections and allow system needs, notably in

terms of flexibility, to be taken into account. The French capa-

city mechanism is not being introduced as a standalone ini-

tiative, but rather in the light of all the measures taken and

their positive effects. In other words, these measures cannot

be substituted for the capacity mechanism, which remains

necessary to generate an additional signal targeting security

of supply.

Without a capacity mechanism in place, these measures cannot

address the existence of externalities discussed in chapter 1.

In addition, measures must be planned taking into account

the time dimension. These actions are not taken on the same

timescale, and their effects on the supply-demand balance are

not simultaneous. For instance, it takes at least ten years to build

an interconnection, whereas new demand response capacity

can be made available with much shorter time constraints. The

European Commission’s checklist does not address this time

dimension.

It can also be advisable to introduce a capacity mechanism

before an imminent threat to security of supply is identified:

Waiting entails a significant risk, because it is not possible to

monitor the market and forecast generation adequacy with

sufficient certainty, far enough into the future, to allow time

for policy intervention when it becomes apparent that a shor-

tage of generating capacity looms.

[…]

The smoother transition and the lower risk to the reliability

of service are arguments in favor of a ’preventive’ strategy323.

Indeed, measures are less effective when taken curatively and

in haste than when their effects are proportionate to their

objective.

10.2.2 Principle of proportionality

Having established the necessity of the mechanism, this sec-

tion discusses its proportionality: the capacity mechanism

implemented in France should not go beyond what is strictly

necessary to meet the objective of security of supply as an aim

of public interest. In other words, it must be demonstrated that

the market architecture adopted is best suited to the objectives

pursued.

The compatibility of this market architecture with the European

Commission’s recommendations will also be discussed.

10.2.2.1 Proportionality regarding the security of

supply objective

The information in chapters 2 through 7 of this report can be

used to evaluate the proportionality of the architectural choices

made to the security of supply objective, or in other words to

demonstrate that these choices do not go beyond what is

strictly necessary to meet this objective.

A market-based architecture was chosen because it ensures

economic efficiency by allowing obligated parties to trade certi-

ficates to minimise the cost of their capacity obligation.

A market-wide mechanism was adopted to ensure that secu-

rity of electricity supply is truly guaranteed and to avoid discri-

minating between market participants. It also creates the right

incentives for demand to participate in the capacity mechanism,

thereby increasing competition.

Insofar as suppliers can cover their obligation by trading in a

decentralised market, the French capacity mechanism pre-

serves the responsibility structure of energy markets where

investments are concerned and avoids having public authorities

make decisions in lieu of market participants. Parties subject to

obligations in the capacity market are responsible for forecas-

ting their customers’ needs, covering these needs, and settling

any differences between their coverage and actual results. The

positive aspect of a decentralised market architecture on the

responsibility of market participants is reflected by economic

efficiency and proper cost allocation, and thus upholds the prin-

ciple of proportionality. 323[De Vries, 2006]

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COMPLIANCE WITH EUROPEAN PROVISIONS AND PRINCIPLES / 10

One key priority for RTE in applying the provisions of the decree

in the proposed rules was to ensure that power system stake-

holders’ real contributions to security of supply are accurately

reflected. Five key choices demonstrate this priority:

> A mechanism based on available capacity is consistent with

the proposal to adopt a market-wide capacity mechanism and

ensure that capacities are rewarded based on their real contri-

bution to security of supply;

> Using a demand-based approach to define the capacity com-

mitment period – i.e. securing commitments for the periods

when demand is highest – is a way to ensure that the capacity

mechanism’s effects target the needs of the power system

when security of supply is threatened;

> The parameters used for calculating suppliers’ capacity obliga-

tion – such as the security factor – and the amount of certificates

issued for capacity – for instance technical constraints impacting

the capacity’s contribution to reducing the shortfall risk – must

be set in such a way as to reflect as accurately as possible the real

contribution of suppliers to the shortfall risk and the real contribu-

tion of capacities to reducing the shortfall risk;

> Taking into account actual measurements for consumption

and capacity availability during the delivery year allows the

contribution of each market stakeholder to security of supply

to be recognised. Small imbalances between the data submit-

ted and actual results lead to a mere adjustment. To ensure

a balance between this need for individualisation and market

stakeholders’ request for stability and predictability, a norma-

tive approach can also be taken in calculating capacity levels

for intermittent capacity;

> The methods used to calculate capacity obligations and cer-

tify capacity must be defined in such a way as to guarantee

non-discrimination between the implicit and explicit valuation

of demand response. To ensure that demand response capa-

cities effectively contribute to security of supply, capacities

that are certified must be subjected to the same availability

commitments as generation capacities during the period

considered (PP2), and demand-side management measures

factored into the reduction of suppliers’ obligations must be

effectively activated during the period considered for the cal-

culation of the obligation (PP1).

In drafting the capacity mechanism rules, special attention was

also paid to ensuring that stakeholders would have confidence

in the “capacity certificate” product, this being essential to facili-

tating trading and allowing the capacity mechanism to produce

effects proportionate to the security of supply objective. For ins-

tance, the decision to publish the mechanism parameters and

stabilise them over the entire mechanism term guarantees that

trading will be conducted in a steady regulatory framework, and

that the value of the product will not be modified due to inter-

vention from outside the market. Moreover, the fact that capa-

city certificates are recorded in a register held by RTE makes the

product credible. In this regard, the architecture adopted, similar

to that of the energy market, enables bilateral trading, and lays

the groundwork for an exchange platform on which supply and

demand can be matched.

Various provisions have been included to ensure that stakehol-

ders in the capacity market will have full knowledge of the security

of supply outlook. In addition to RTE’s Adequacy Forecast Reports,

which is already published by RTE, they will be able to consult the

data in two registers that RTE will make open to the public:

> The certified capacity register, which will list all certified capa-

cities individually;

> The peak demand management register, where all demand-

side measures impacting the mechanism will be recorded.

The choices allowing the implicit participation of foreign capaci-

ties in the mechanism initially and the milestones set for a pos-

sible explicit participation further out are also taken into account

in assessing the capacity mechanism’s proportionality to the

security of supply objective for France.

10.2.2.2 Compatibility with the European Commission’s

recommendations on market design

The European Commission looks first at the type of capacity

mechanism proposed and had expressed a preference for

targeted mechanisms such as strategic reserves and one-off

tenders. The reasoning behind the adoption of a market-wide

mechanism is discussed in detail in chapter 2 of this report, with

evidence to support that strategic reserves or one-off tenders

would not meet the security of supply objective in a proportio-

nate manner. For instance, a strategic reserve would, in France,

result in excess capacities being created to meet the physical

needs of the power system during peak demand periods, which

are the primary risk for the French power system.

RTE’s analysis shows that the design of the French capacity

mechanism complies with all of the European Commission’s

All findings presented in this report show that the architecture adopted for the French capacity mechanism, as described in the decree and RTEs proposed rules, is proportionate to the objective of ensuring security of supply.

228

recommendations except with regard to the par-

ticipation of cross-border capacities. This specific

recommendation in partially addressed in the pre-

sent chapter as well as in 9. The information provi-

ded shows that a mechanism that initially allows the

implicit participation of cross-border capacities and

lays out steps to be taken to subsequently enable

their explicit participation is compatible with the European Com-

mission’s recommendations.

The table below provides an overview of the issues discussed in

detail in the previous chapters to demonstrate the compatibility

of the French capacity mechanism with the European Commis-

sion’s other recommendations.

324Enel Produzione case cited above, paragraph 75: “As regards the duration of the intervention provided for under the legislation at issue in the main proceedings, it must be limited to the length of time that is strictly necessary for attaining the objectives which it pursues. In that regard, it must be held that, since the list of essential installations is annually reviewed and updated, it would appear that installations are not kept on it for more than a limited period”.

Table 7 – Compatibility of the French mechanism with the European Commission’s recommendations presented during the RTE WG, 5/12/13

Guideline RTE analysis

Participation of new and existing capacities Participation of all capacities in the mechanism.

Technological neutrality Single product, certification based on technical performances.

Zero price in situations of excess capacity Market price: excess supply will drive the price toward 0.

2/4 year timescale Mechanism term starting in Y- 4, shorter timescales possible to better fit with demand response.

No export restrictionsNo clause specifying the destination of energy produced by capacities participating in the mechanism.

No restrictions on energy sales No price caps associated with participation in the capacity mechanism, no restrictions of offers.

No inefficient production The capacities participating in the mechanism commit to availability, not production.Commitment periods are limited (short PP2 period).

No impact on coupling or intraday

No changes affecting the functioning of energy markets or stakeholders' behaviours (marginal cost offers).

Participation of demandPerfectly compatible mechanism with two forms of participation possible (implicit/explicit) to better reflect the specific characteristics of demand response.Mechanism encouraging better consumption behaviours.

Real adequacy guarantees with unnecessary excess costs avoided

Commitments secured for all capacity: the fact that all capacities are committed to availability enhances security of supply benefits. Capacity that is not available is not rewarded through the capacity mechanism.Market price: the price tends toward zero in situations of overcapacity.Importance of measuring actual results to guarantee that market results reflect reality.

Virtuous cost allocation

The obligation reflects the contribution to the shortfall risk = to ensure a virtuous allocation of costs, the obligation must be calculated carefully taking into account the specific characteristics of demand with stakeholders being held responsible individually.There are no exemptions from the obligation.

Transitional mechanism

With a market-based mechanism, the price reflects the real value of the capacity need, and will tend toward zero if no capacity is needed; it will be possible to review how this system functions based on CRE's annual reports on the mechanism and reassess it if necessary.CRE will report annually on the mechanism’s functioning and integration into the European market. The European Court of Justice determined in its Enel Produzione decision that a measure that is reviewed and reassessed annually can be considered transitional 324.

RTE considers that the French capacity market design is compatible with the European Commission’s recommendations and does not go beyond what is necessary to ensure security of supply in France.

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COMPLIANCE WITH EUROPEAN PROVISIONS AND PRINCIPLES / 10

10.3 Conclusion

The introduction of a capacity mechanism in France, as provi-

ded for in the NOME Act, must be considered within a European

perspective. Indeed, while security of supply is ensured through

European Union Member States’ energy policies, there is in rea-

lity a high degree of interplay between the policies adopted by

Member States in an integrated market.

While the European Union has competence in energy-related

matters, security of supply is a Member States competence,

according to the provisions of article 194 of the TFEU. In this

regard, the EU acquis does not prohibit public intervention to

guarantee security of supply, and capacity mechanisms are

included in the measures listed in Directive 2005/89/EC of the

European Parliament and of the Council of 18  January 2006

concerning measures to safeguard security of electricity supply

and infrastructure investment.

Analysis of the legal framework governing public intervention in

the energy sector in Europe shows that two forms of public inter-

vention are possible for capacity mechanisms: State aid and public

service obligations, as provided for in Directive 2009/72/EC.

It is not RTE’s place to determine the legal qualification of the

capacity mechanism, though the architecture adopted for the

mechanism can be considered with regard to the framework

for public service obligations. The obligation is imposed on

suppliers, which contribute to compliance with the security of

supply criterion set by public authorities by having sufficient

capacities to ensure electricity supply to their final customers.

Generators are required to participate in the mechanism and

ensure that it functions properly by having all of their generation

capacity certified. The commitments undertaken during the

certification process to make certified capacity available ensure

that the capacity will effectively contribute to security of supply

during peak periods.

That being said, regardless of how the capacity mechanism

is qualified, the legality of the public intervention is evaluated

notably based on necessity and proportionality tests, particu-

larly based on the specific analytical framework proposed in the

Staff Working Document “Generation Adequacy in the internal

electricity market - guidance on public interventions”.

Regarding necessity, RTE’s Adequacy Forecast Reports comply

with the European Commission’s recommendations:

> Demand forecasts take into account EU energy and climate

policy (particularly with regard to demand management);

> Supply forecasts take the internal market into account

through estimates of generation capacity in Europe;

> Simulations are carried out using a probabilistic approach with

a careful modelling of contingencies and their correlations

(particularly for variable sources);

> All requirements in terms of transparency and stakeholder

consultation are met.

The results presented in the most recent update of the Ade-

quacy Forecast Report (2013), outlined in chapter  1 of this

report, show that safety margins vis-à-vis the security of supply

criterion will gradually shrink and then disappear in 2017. This

suggests that security of supply in France will have to be care-

fully monitored and will be at risk in 2017, particularly if a cold

spell occurs.

Actions undertaken to increase liquidity in French electricity

markets also comply with the European Commission’s recom-

mendations, notably by supporting projects to integrate the

European market over all time horizons, since they allow

demand response to participate in all market mechanisms

over all timescales, and by fostering the continued develop-

ment of interconnections between France and neighbouring

countries.

These measures all promote the integration of markets and

improve how they function. In this regard, they help correct

market imperfections and allow system needs, notably in

terms of flexibility, to be taken into account. That being said,

the French capacity mechanism is not being introduced as a

standalone initiative, but rather in the light of all the measures

undertaken and their positive effects. In other words, these

measures cannot be substituted for the capacity mechanism,

which is necessary to generate an additional signal targeting

security of supply.

As regards proportionality, the analyses presented in this report

demonstrate compliance with the European Commission’s

recommendations and show that the choices made are pro-

portionate to the objective of ensuring security of supply. The

one remaining open point is the participation of cross-border

capacities in the mechanism. Indeed, some legitimate questions

can be raised about the compatibility with European rules of the

230

decision to account for the contribution of foreign capacities to

security of supply in France implicitly. It should be noted that

this implicit solution results in a high degree of economic effi-

ciency. By reducing domestic capacity needs and thus avoiding

situations of overcapacity, the contribution of foreign capacities

to security of supply is already factored in as a positive exter-

nality. Moreover, chapter  9 features a roadmap outlining the

specific milestones included in the rules for moving toward a

target mechanism that explicitly recognises the contribution of

foreign capacities to security of supply in France and discusses

the kind of market architecture that would allow such effective

participation. The European Commission considers this to be

one possible approach.

RTE thus considers that the French capacity mechanism takes

into account the provisions of the EU acquis, particularly those

included in Directives 2009/72/EC and 2005/89/EC, and that

it complies with the principles of necessity and proportionality

described in the European Commission’s recommendations.

231

COMPLIANCE WITH EUROPEAN PROVISIONS AND PRINCIPLES / 10

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BIBLIOGRAPHIE

234

ANNEXE 1: LIST OF PARTICIPANTSIN MAC CONSULTATION

RTE contributors:

Clotilde LEVILLAIN (Présidente de la CAM) (RTE)

Mathilde BOURIGA (RTE)

Colas CHABANNE (RTE)

Mathieu CHUPIN (RTE)

Jean-Jacques COURSOL (RTE)

Gabriel DA-SILVA (RTE)

Christophe DERVIEUX (RTE)

Anne DUBUISSON (RTE)

Arthur HUBERT (RTE)

RTE would like to thank all participants in the consultation:

Chloé LATOUR (RTE)

Cédric LEONARD (RTE)

Céline MARCY (RTE)

Bruno MENU (RTE)

Marie PETITET (RTE)

Rebecca NAKACHE (RTE)

Thomas VEYRENC (RTE)

Gérald VIGNAL (RTE)

Hervé LEXTRAIT (EDF)

Christophe TRZPIT (EDF)

Nicolas BARBANNAUD (EDF-T)

Bertrand CHAMINAUD (EGL)

Vincent HOFFBECK (ELECTRICITE DE STRASBOURG)

Alexis JACQUILLARD (ELECTRICITE DE STRASBOURG)

Marc KOENIG (ELECTRICITE DE STRASBOURG)

Benoit DOIN (ENEL)

Juan LOPEZ-TERRADAS (ENEL)

Anne-Soizic RANCHERE (ENERGY POOL)

Emilie SCHOLTES (ENERGY POOL)

Emmanuelle CARPENTIER (EON)

Maëlle DURANT (EON)

Emmanuelle JOUBERT (EON)

Gad PINTO (EON)

Bruno GAILLARD (EOS)

Aurore LANTRAIN (EPEX SPOT)

Audrey MAHUET (EPEX SPOT)

Rémi OUDOUL (EPEX SPOT)

Florence ARNOUX-GUISSE (ERDF)

Remi GRASSET (ERDF)

Christophe GROS (ERDF)

Mehdi HAJJAM (ACTILITY)

Géry LECERF (ALPIQ)

Natacha HAKWIK (ALPIQ)

Pierre BAUD (ANPEEP)

Sylvain ROMIEUX (ANROC)

Barbara WUYTS (AXPO)

Quentin HARLE (COFELY)

Yann MICHEL (CRE)

Aurélien PAILLARD (CRE)

Emmanuel WATRINET (CRE)

Antoine CARON (DGEC)

Etienne HUBERT (DGEC)

Thibault LEINEKUGEL (DGEC)

Antoine PELLION (DGEC)

Julien TOGNOLA (DGEC)

David CHANTELOU (DIRECT ENERGIE)

Fabien CHONE (DIRECT ENERGIE)

Arnaud BORTOLOTTI (EDF)

Julian BOUCHARD (EDF)

Clotilde BRETON (EDF)

Richard COMBESCURE (EDF)

Jean-Christophe GAULT (EDF)

235

ANNEXES

Coralie NASLIN (ERDF)

Alexis SAUVAGE (ERDF)

Johann ZAMBONI (FLEXIWATT)

Francisco DELFINI (FNSICAE)

Raphael LAUBRÉAUX (FNSICAE)

Jean-Michel MICLO (FNSICAE)

Alain FUSER (GDF-SUEZ)

Stephane HECQ (GDF-SUEZ)

Redha LOUIDA (GDF-SUEZ)

Chantal LY (GDF-SUEZ)

Arnault MARTIN (GDF-SUEZ)

Patrick GODFRIN (GEG/ELE)

Sandra EDOU (HEX)

Aurora ALVAR MIRO (IBERDROLA)

Guillaume FAUCONNIER (MARKENER)

Aurélie LEMERCIER (NOVAWATT)

Philippe COUCHE (Planete OUI)

Jean ANGOTTI (POWEO Pont sur Sambre Production)

Stéphanie BOUCHET (POWEO Pont sur Sambre Production)

Thomas ULRICH (RWE)

Maxime DAUBY (SGE)

Antoine DEBROVES (SGE)

Philippe GAY (SGE)

Pascal GAT (SNCF)

Claude CONRARD (SOLVAY)

Julien DELAGRANDANNE (SOREGIES/ELE)

Lillian DALE (STATKRAFT)

Thibault CHRISTEL (TOTAL)

Baptiste MAMET (UEM)

Gildas BARREYRE (UNIDEN)

Stephane DELPEYROUX (UNIDEN)

Sophia ELASRI (UNIDEN)

Raphaelle IMBAULT (UNIDEN)

Dorothée COUCHARRIERE (VATTENFALL)

Laurence MARTIN (VATTENFALL)

Stephane CHANCY (VERBUND)

Pierre BIVAS (VOLTALIS)

Nicolas GAULY (VOLTALIS)

Jérôme SIMON (WATTVALUE)

236

Workgoup/Questionnaire # Stakeholders

Q1 28/01 Basic parameters 14Alpiq, ELD, EDF, Enel, Energy Pool, ERDF, EON, GDF Suez, NovaWatt, Direct Energie, SmartGrid Energy, Statkraft, Total Gas & Power, UNIDEN

WG of 07/02 on questionnaire 1 3 RTE, EDF, GDF Suez

Q2 12/02 Obligation 12Alpiq, ELD, EDF, Enel, Energy Pool, ERDF, EON, GDF Suez, Direct Energie, SmartGrid Energy, Statkraft, UNIDEN

WG of 19/02 on questionnaire 2 2 RTE, UNIDEN

Q3 20/02 Certification 13Alpiq, ELD, EDF, Enel, Energy Pool, ERDF, EON, GDF Suez, NovaWatt, Direct Energie, SmartGrid Energy, Statkraft, UNIDEN

WG of 27/02 on questionnaire 2 (continued) 3 RTE, EDF, ERDF

WG of 20/03 on questionnaire 3 4 RTE, EDF, ERDF, GDF Suez

WG of 02/04 on overall scheme 2 RTE, Direct Energie

WG of 25/04 Illustrations 2 RTE, EDF

WG of 17/05 Settlement 4 RTE, EDF, Energy Pool, GDF Suez

WG of 29/05 Certification of controllable capacities 6 RTE, EDF, Energy Pool, EON, GDF Suez, UNIDEN

WG of 07/06 Obligation parameters 3 RTE, EDF, GDF Suez

WG of 19/06 Certification of intermittent capacities and reduced contribution

3 RTE, EDF, ERDF

WG of 28/06 Capacity verification 4 EDF, ERDF, EON, GDF Suez

WG of 09/07 Calculation of obligation 3 RTE, EDF, ERDF

WG of 02/10 Draft rules, parts 1 to 4, 7 and 8 7 Alpiq, EDF, ENEL, EON, EPEX SPOT, ERDF, GDF-Suez

WG of 09/10 Draft rules, part 5 8 Alpiq, Direct Energie, EDF, ENEL, Energy Pool, EON, ERDF, GDF-Suez

WG of 14/10 Draft rules part 6 7 Alpiq, EDF, ENEL, Energy Pool, EON, ERDF, GDF-Suez

Feedback from consultation on draft rules 16

Alpiq, Direct Energie, ELD, EDF, EFET, Energy Pool, EON, ERDF, GDF-Suez, Novawatt, Poweo Pont sur Sambre Production, SGE, Statkraft, UIC, UNIDEN, Voltalis

WG of 14/11: Exchanges, transparency and competition in the market

1 RTE

WG of 22/11 Treatment of intermittent capacities 2 RTE, EDF

WG of 28/11 Calculation of temperature sensitivity 3 RTE, Direct Energie, EDF

WG of 05/12 Capacity monitoring and verification; European aspects 3 RTE, ERDF, GDF-Suez

All contributions can be found on the CURTE concerte website (https://concerte.fr).

ANNEXE 2: CONTRIBUTIONS TOTHE STAKEHOLDER CONSULTATION

RTE Réseau de transport d’électricité, Société anonyme à Directoire et Conseil de surveillance au capital de 2 132 285 690 € - RCS Nanterre 444 619 258Conception & réalisation : Good Eye’D - ©Fotolia - Impression sur papiers issus de forêts gérées durablement.