FRAMEWORK FOR NEW ELECTRICITY
MARKET DESIGN
A report to France Energie Eolienne
FRAMEWORK FOR NEW ELECTRICITY MARKET DESIGN
September 2014
FRAMEWORK FOR NEW ELECTRICITY MARKET DESIGN
Contact details
Name
Email
Telephone
Simon Bradbury
[email protected]
00441865812239
Julien Cosse
[email protected]
0033156882712
Pöyry is an international consulting and engineering company. We serve clients globally
across the energy and industrial sectors and locally in our core markets. We deliver
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Pöyry Management Consulting provides leading-edge consulting and advisory services
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TABLE OF CONTENTS
EXECUTIVE SUMMARY
1.
2.
3.
4.
5.
6.
7.
8.
1
Context
1
Recommendations
2
Conclusion
8
INTRODUCTION
11
1.1
Context
11
1.2
Objectives and focus
12
GRID ACCESS
13
2.1
Current situation
13
2.2
Recommended market design enhancements
15
WHOLESALE MARKET
19
3.1
Current situation
19
3.2
Recommended market design enhancements
21
IMBALANCE ARRANGEMENTS
23
4.1
Current situation
23
4.2
Recommended market design enhancements
26
RES SUPPORT
31
5.1
Current situation
31
5.2
Recommended market design enhancements
33
RETAIL
39
6.1
Current situation
39
6.2
Recommended market design enhancements
40
CARBON REGIME
43
7.1
Current situation
43
7.2
Recommended market design enhancements
44
RECOMMENDATIONS AND NEXT STEPS
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EXECUTIVE SUMMARY
Context
Across Europe, electricity markets are undergoing transformation. The generation mix is
changing with the growing contribution from renewable energy sources (RES), such as
wind and solar. Conventional generation faces reduced operating hours and lower
profitability and is seeking new sources of revenue. Meanwhile, the advance of ‘smart’
technologies has the potential to change patterns of demand.
The traditional model of electricity market design which was based on dispatching large
scale, controllable thermal generation to meet predicted demand is becoming less
relevant. Market arrangements must evolve to reflect the new order in which renewables
are a mainstream component of the generation mix, conventional generation plays a
supporting role and demand is flexible according to the needs of the system. Renewables
and demand must be integrated into the electricity markets of the future.
The EC’s ‘Target Model’ for cross-border electricity trading and the recently adopted EC
State Aid Guidelines give additional impetus to this transition, requiring adaptation to the
design of electricity trading arrangements (including balancing responsibility for
renewables as a crucial step to their market integration) and to support mechanisms for
renewable generation technologies.
There are two intertwined objectives for the future electricity arrangements: to integrate
renewables within the market and to make the market fit for purpose for a high RES
future. To support these objectives, we propose a series of recommendations which
cover the regime for CO2 and renewable support, grid access, through to wholesale and
retail market arrangements.
This report outlines recommendations for market design that work towards these goals for
France, through a series of building blocks that contribute to an overall market design.
These recommendations are not wind specific and were not designed to favour this
technology over others, but have the objective of improving the effectiveness of the whole
market.
The recommendations are presented as a package of complementary measures to be
progressed in tandem to support the integration of renewables into the market. They are
necessary requirements to meet the policy objectives of balancing responsibility and
increased wholesale market exposure for renewable generators. They enhance the
market arrangements to allow renewable generators to manage risks linked to market
participation. Without this package of recommendations, parties will have reduced ability
to manage market risk, which is likely to increase prices for consumers and frustrate
efficient market operation.
The recommendations are focused on arrangements for future projects. Arrangements for
existing projects should continue to operate as originally intended to avoid retrospective
change and the destabilising effect that this can have on future investors. Therefore, it is
vital that retrospective changes are not made, which would undermine confidence, and
that the existing Feed-in Tariff (FiT) is grandfathered for projects developed under it.
Revisions to the future scheme should not alter the support afforded to projects being
developed under the existing FiT1.
1
It may be worth considering giving projects under the existing support scheme the choice to
switch to an amended support scheme at their discretion.
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Recommendations
Our recommendations span a number of issues and taken together represent a holistic
market design suitable for renewable and conventional generation and for demand:
§
grid access: basis for connecting to and accessing the grid;
§
wholesale market: availability of products and liquidity for trading;
§
imbalance arrangements: nature of imbalance risk and options for managing it;
§
RES support: basis for RES support that supports market integration;
§
retail: role of demand side and reflection of consumer preferences; and
§
carbon regime: details of broader carbon pricing framework.
The recommendations are summarised in Table 1 and outlined further in the sections
below.
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Table 1 – Summary of recommendations by building block
Block
Aim
Grid
access
§
Recommendations
Improving certainty,
transparency and
competition
§
§
§
§
Wholesale
market
§
Enhancing access to
market and
developing
appropriate products
§
§
§
§
Imbalance
§
Ensuring costreflective imbalance
prices
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§
§
Grid access should be provided on a
‘connect and manage’ basis and access
rights must be clearly defined and
honoured
The provision of connection works should
be subject to effective competition
Connection charges should be ‘shallow’ in
nature to cover the costs of local/nonshared works only
Network regulation can be enhanced to
better align the interests of the network
businesses with those of system users and
ensure timely development of
infrastructure. This includes extension of
regulatory oversight for distribution network
operators
Internal intraday auctions should be
developed, including cross border with
access to intraday capacity
Trading products should be available at
half-hourly granularity, with cross border
trading
Production forecast and outturn information
should be made available by technology at
transmission and distribution levels
A centralised marketplace for trading
REGOs could be established
Imbalance pricing should be a single price
structure, not dual
Gate closure for trade nominations should
be reduced from 1 hour
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Block
Aim
RES
support
§
Recommendations
Making support more
market-oriented while
limiting exposure to
risks that cannot be
managed
§
Future RES support arrangements in
France should be based on a variable
premium approach with a cost control
mechanism linked to overall end-user
prices
§
Support should be restricted for zero shortrun marginal cost generation in periods of
negative wholesale prices
§
The enduring allocation and price discovery
arrangements should be based on a
competitive auction or tender process,
when conditions for effective competition
are met.
As a transitional measure, allocation should
be determined through an administrative
process, with technology banding and
pricing that reflects pay-as-clear within
bands
Grandfathering of support to existing
projects
§
§
Retail
Carbon
regime
§
§
Stimulating value for
green power and
accessing demand
side potential
§
Allowing carbon to
take over from
dependence on RES
support in a
sustainable, credible
framework
§
§
§
§
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Encourage customers (especially public
entities) to secure a specific portion of
green power in their public tenders
Smart meter rollout needs to be coupled
with dynamic, time of use tariffs in order to
enable price responsive behaviour and
mechanisms to allow aggregated Demand
Side Response to participate in the market
Enhanced institutional credibility for the
carbon regime, ideally broad international
agreement, preferably global or EU
Pre-determined adjustment mechanisms,
such as the proposed Market Stability
Reserve, can help to improve market
functioning
Recycle carbon auction revenue back to
consumers (domestic and/or energy
intensive users in open industries)
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Grid access
Securing physical access to the grid in a timely manner, at an appropriate cost and on a
reliable basis is an essential prerequisite for any generator. The arrangements for
providing connection and on-going access to the grid in France should be enhanced to
adopt international best practice.
At present, project developers face considerable uncertainty regarding the time and cost
of connection, which slows project delivery and increases costs. Then, when operational,
projects cannot rely on continued firm access to the distribution and transmission grids.
Furthermore, incentives for network businesses to create and operate a system to deliver
and support electricity market transition are weak.
To improve the situation, we recommend the following:
§
Provide distribution and transmission grid access on a ‘connect and manage’ basis to
allow projects to access the system within fixed timescales and/or when local
connection works are complete, rather than having to wait for deep grid
reinforcement. This allows developers to secure 100% financially firm access to the
system within fixed timescales and/or from the completion of local works, offering
faster and more controllable connection timescales.
§
Allow effective contestability in the provision of connection works to introduce
competition with the potential for faster connection timescales and reduced
connection costs.
§
Set connection charges on a ‘shallow’ basis to cover the costs of local/non-shared
works only and not costs of wider/shared network reinforcement, based on a
transparent methodology founded on the principle of cost reflectivity.
§
Enhance network regulation to better align the interests of the network businesses
with those of system users as part of the market transition. This can include
incentives relating to connection timescales and a longer-term incentive regime to
support strategic planning by the grid companies. Importantly, this includes extension
of regulatory oversight for Distribution Network Operators (DNOs) (ERDF and non
nationalised distributors) with stricter control and incentives being put on transparency
of connection offers and timely connections. Incentives on timely and effective
connection policy should also be set by CRE, possibly based on a benchmark of
connection timing best practices in Europe.
Wholesale market
Access to liquid wholesale markets across various product timeframes (from year ahead
to intra-day) is a key feature of well-functioning and competitive electricity markets. It
provides a route to market for smaller players and allows market participants to adjust and
match their physical and commercial positions to manage their price and volume risk
exposure.
Today, the majority of forward trade is conducted over-the counter (OTC), which limits
liquidity on centralised platforms. Short-term liquidity is mostly concentrated in the dayahead auction with limited intraday liquidity, which limits full and adequate hedging
possibility and market risk exposure management. Unaltered, this will limit availability of
products and trading routes for renewables operators under the existing FiT arrangements
once they come to an end and also for future operators under new support arrangements.
Also, interconnection capacity is allocated to the day-ahead market in preference over
intraday, which means that cross border trading intraday is limited.
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In response, we recommend the following steps:
§
The arrangements for continuous intraday capacity allocation under the Target Model
must be improved to allocate cross-zonal capacity across timeframes based on
market values not a priori reservations. To supplement this, internal intraday auctions
should be developed, alongside coupled continuous trading, to support development
of liquidity in this timeframe.
§
Arrangements for an off-taker of last resort should also be developed, at least as a
transitional measure, to provide a backstop contractual option while commercial offtake arrangements are developing.
§
To support the route to market for RES, a centralised marketplace for trading of
Renewable Guarantees of Origin (REGOs) should be established, as a stand-alone
product alongside power trading products.
Imbalance arrangements
Imbalance settlement (or ‘cashout’) arrangements are a vital part of wholesale trading
arrangements, providing the route for commercially settling differences between physical
and contractual positions. FiT supported renewable generators do not currently bear
imbalance risk exposure, as it is transferred to the off-taker. But this will have to change if
renewables are to be integrated to the wider market. Renewables projects being
developed under future RES support schemes will have to face imbalance exposure2 as it
is now a compliance requirement with the EU Target Model and the EC State Aid
Guidelines.
The current imbalance arrangements are based on dual prices, which place different
value on imbalances in opposing directions within the same settlement period. This has a
particular relevance for autonomous generation such as wind, which may have an
imbalance position in the opposite direction to the overall system imbalance. Dual pricing
undervalues the benefit to the system of this reverse imbalance and works against the
interests of wind generation.
There is also a misalignment between the settlement period duration of 30 minutes and
the smallest block that can be traded, which has 1 hour duration. This means that it is not
possible to shape contractual positions down to the half-hourly level, even though this is
the timeframe for settlement. In addition, contractual trade nominations must be made
one hour before real time, which may not enable latest forecast positions to be covered
through trade activity.
These factors make the design of the imbalance arrangements an important issue for
current installations post FiT and future projects, and there are several areas where
enhancements can be made:
§
The value of imbalance positions in the opposite direction to the system should be
acknowledged by switching from a dual to a single imbalance price structure, with the
single price based on the cost of resolving imbalances in the same direction as the
net system imbalance.
§
Ensure half -hourly products are available on traded market (including cross-border)
so that parties are able to trade at a granularity that matches the 30 minute settlement
period.
2
However, neither the EC State Aid Guidelines nor the EU Target Model prevent future RES
support regimes from allowing recovery of imbalance costs through some measure.
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§
Shorten gate closure for trade nominations to below 1 hour.
RES support
The current FiT support scheme for renewables is not expected to endure indefinitely and
is expected to change. The European Commission’s State Aid guidelines place emphasis
upon developing a more market based type of support for future schemes and require that
supported renewable generators sell directly into the market and are subject to market
obligations.
New RES support arrangements for future projects must change to be compatible with
these requirements. Clearly, however, existing projects under the current support scheme
should be permitted to continue to operate within these arrangements for the remainder of
the defined support period to avoid retrospective change and the destabilising effect that
this can have on future investors3. Therefore, it is vital that retrospective changes are not
made, which would undermine confidence, and that the existing FiT is grandfathered for
projects developed under it. Revisions to the future scheme should not alter the support
afforded to projects under the existing FiT4. Going forward, we recommend:
§
Future RES support arrangements in France should be based on a variable premium
approach. A variable premium limits the exposure of renewable generators to
movements in wholesale market prices, providing greater certainty to investors and
operators in terms of potential revenue streams. It does still require market
interaction, however, given the need for projects to secure wholesale market revenue
streams. While the support cost is variable, overall costs to consumers can be
managed through application of a cost control mechanism.
§
To be consistent with State Aid guidelines and address concerns regarding incentives
to bid negatively and so mitigate the potential for distortionary effects, the proposed
variable premium approach should be combined with a mechanism to limit support
paid to zero SRMC generation in periods of negative wholesale prices.
§
A competitive auction or tender process for allocating RES support could be
established when conditions for effective competition are met, but this is not the case
now as flagged below.
§
The use of auctioning is not a practical option in France in the near-term given
uncertainty and timeframes linked to the current planning and grid access
arrangements. Until these arrangements are enhanced and greater certainty is
available for developers, allocation should be administrative as a transitional
measure. Under an administrative process, allocation should be banded by
technology, with a pay-as-clear price determined for each band.
3
Existing RES onshore wind generators are given the option to opt-out from the FiT “contrat
d’achat” and switch to market based revenues (or new support arrangements when those
are in place), subject to the penalty clause (XIII-6) specified in the latest contracts (“Contrat
d'achat de l'énergie électrique produite par les installations utilisant l’énergie mécanique du
vent et bénéficiant de l’obligation d’achat d’électricité” adopted on 30 July 2014) and the
payment of an exit fee.
4
It may be worth considering giving projects under the existing support scheme the choice to
switch to an amended support scheme at their discretion.
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Retail
The advance of ‘smart’ technologies allows enhanced integration of the demand side into
the market. The future role of the consumer as method for balancing production
intermittency is, therefore, important. In addition, the public perception of the value of
green energy is key to the development of renewable production. Where consumers may
attach a premium to green energy, retailers should be able to reflect this in their offerings
and to drive a demand for REGOs to back up their green supplies.
Currently, the retail market in France is still heavily bound to regulated tariffs and the
development of innovative offers from the utilities (including green energy and dynamic
price offerings) is limited. To alter this situation, we recommend the following:
§
Encourage customers (especially public entities) to secure a specific portion of green
power in their public tenders. Where there is willingness to pay, this will drive
demand for and also the value of REGOs.
§
To take advantage of potential smart meter functionality, this roll-out needs to be
coupled with dynamic time of use tariffs in order to enable price responsive behaviour
from the demand side and mechanisms to allow aggregated demand side resources
to participate in the market in a meaningful manner. This could bring new sources of
flexibility to the intraday markets and help with the balancing of wind.
Carbon regime
Experience from the EU ETS during Phases II and III highlights that carbon prices have
been insufficient to deliver investment in low carbon generation. The current carbon
regime is not a bankable proposition for low carbon investment.
The ultimate term goal is for an effective carbon regime that allows for investment in low
carbon generation without the need for out-of-market support and integrates low carbon
generation fully into the market. Achieving this relies on enhanced institutional credibility
for the carbon regime. Ideally, this would be in the form of broad international agreement
(preferably global or, as a second best, European) with associated treaties. This can be
supported by the introduction of an independent carbon bank to reduce political influence
on the mechanics and operation of the carbon regime. Additionally, pre-determined
adjustment mechanisms, such as the proposed Market Stability Reserve, can help to
improve market functioning and so bolster long-term credibility of the carbon regime.
Conclusion
Electricity market design needs to evolve to integrate renewables within the market and to
make the market fit for purpose for a high RES future. The recommendations outlined
above provide practical options for enhancing the French electricity market design in
pursuit of these twin goals. They provide greater certainty in relation to grid access and
improved routes to market and trading options, while integrating RES within the market.
Critically, these proposals can provide a bridge to the ultimate objective of removing
support mechanisms for established RES.
Table 2 highlights, for each of the market design building blocks where proposals were
made, potential consequences of not implementing the recommendations.
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Table 2 – Consequences of not implementing recommendations
Block
Aim
Recommendations
Grid
access
§
Improving certainty,
transparency and
competition
Continued uncertainty for developers regarding
timing and costs of connection will slow project
delivery and increase costs
Wholesale
market
§
Enhancing access
to market and
developing
appropriate
products
Persistence of limited liquidity on the intraday
market and absence of half-hourly products (with
cross border trading) will restrict the ability for
generators to manage risks linked to balancing
responsibility
Imbalance
§
Ensuring costreflective
imbalance prices
Maintaining the dual price approach will continue
to undervalue imbalances in the opposite
direction to the system position, affecting
autonomous generation in particular
RES
support
§
Making support
more marketoriented while
limiting exposure to
risks that cannot be
managed
While the existing FiT can still persist if unaltered
in accordance with State Aid guidelines, this will
not facilitate the integration of RES within the
market. Adopting the proposed RES support,
once all the recommendations for integration of
RES into the electricity market have been made,
will allow RES to be progressed within a workable
balance of risk and reward
Retail
§
Stimulating value
for green power
and accessing
demand side
potential
Green energy will be undervalued and the ability
for the demand side to contribute to a more
efficient system will not be realised
Carbon
regime
§
Allowing carbon to
take over from
dependence on
RES support in a
sustainable,
credible framework
If the carbon regime is weak and the supporting
framework lacks enduring credibility, the external
costs linked to carbon will continue to have a
minor effect on wholesale price formation,
extending the period over which RES support is
needed
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1.
1.1
INTRODUCTION
Context
Across Europe, electricity markets are undergoing transformation. The generation mix is
changing as the penetration of renewable generation technologies, such as wind and
solar, increases in pursuit of ambitions for power sector decarbonisation. At the same
time, electricity demand is also evolving. Greater electrification of heat and transport will
increase overall demand, while the advance of ‘smart’ technologies has the potential to
change patterns of consumption. The conventional model of electricity market design
based on dispatching large scale, controllable thermal generation to meet predictable
patterns of demand is, therefore, becoming less relevant. Market design must evolve to
reflect the new order.
The growth in renewable generation penetration has generally been backed by support
schemes to allow technologies to develop and become more established. Support
schemes vary in nature, but they have tended to shelter renewables from the market to
some extent, rather than include them within it. Now, renewables are a mainstream
component of the generation mix and certain technologies can be classed as mature. In
this context, renewables (and flexible demand) must be integrated to the electricity market
designs of the future.
This ambition to integrate renewables with the market is endorsed by policy makers in the
European Commission (EC). The European Target Model5 for electricity endorses the
principle of Balance Responsibility for all market participants. This is supported by new
EC State Aid guidelines for renewable support6, which require that supported generators
are subject to standard balancing responsibilities and must sell their output directly into
the market.
There are, therefore, clear drivers for modifications to electricity market design and RES
support mechanisms. There are two intertwined objectives: to integrate renewables within
the market and to make the market fit for purpose for a high RES future, in pursuit of an
ultimate goal in which mature technologies do not require out of market support.
5
The Target Model is designed to deliver a framework for the efficient cross-border trading of
electricity across Europe. It includes allocation of capacity as part of energy trading
arrangements, provisions to allow cross-border sharing of balancing resources and
harmonised imbalance pricing.
6
Guidelines on State aid for environmental protection and energy 2014-2020 (2014/C
200/01).
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1.2
Objectives and focus
In this context, this report provides recommendations for the design of the French
electricity market that will improve market functioning and enhance the integration of
renewables into the market for a system with significant renewable penetration.
We developed our recommendations drawing on the following steps:
§
assessment of the current situation in France and the issues faced by market
operators;
§
review of current regulatory arrangements and future initiatives in France;
§
review of EU regulatory framework including the Target Model and State Aid
guidelines; and
§
understanding of international experience and market design in other markets.
These steps enabled the identification of issues within the current French market design,
prioritisation of their importance and consideration of possible options for adoption in the
future market design.
We have chosen to focus on a selection of important building blocks that collectively
contribute to the overall market design arrangements:
§
grid access: basis for connecting to and accessing the grid (Section 2);
§
wholesale market: availability of products and liquidity for trading (Section 3);
§
imbalance arrangements: nature of imbalance risk and options for managing it
(Section 4);
§
RES support: basis for RES support that supports market integration (Section 5);
§
retail: role of demand side and reflection of consumer preferences (Section 6); and
§
carbon regime: details of broader carbon pricing framework (Section 7).
The recommendations (Section 8) are intended to provide a framework within which
existing renewables projects can operate when they come out of the current FiT support
scheme and that allows continued investment in new projects. These recommendations
are not wind specific and were not designed to favour that technology over others, but
have the objective are intended to apply for all technologies to improve the effectiveness
of the whole market.
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2.
GRID ACCESS
Securing physical access to the grid in a timely manner, at an appropriate cost and on a
reliable basis is an essential prerequisite for any generator. The arrangements for
providing connection and on-going access to the grid in France could be enhanced to
adopt international best practice. These arrangements are in need of reform as part of the
electricity market transition.
We focus our attention upon three particularly high priority areas:
§
grid access allocation and rights;
§
arrangements for providing connections charging; and
§
incentive regulation for network businesses.
2.1
Current situation
2.1.1
Context in France
Figure 1 provides an illustration of installed wind capacity, wind connected and awaiting
connection by region as defined by ERDF (EDF Réseau Distribution France). Although
development of wind capacity had been growing relatively steadily, there was still around
3.8GW of capacity awaiting connection by mid-2013 on ERDF network7. On the high
voltage transmission network operated by RTE (French TSO), a little more than 1.4GW of
onshore wind projects were in planning (110MW had a connection agreement) at the end
of 2012.
Grid connection and access is currently a lengthy process (several years) and anecdotal
evidence suggests it could take up to eight years between project development and
operation. Grid access rights for existing projects under Feed-in Tariff (FiT) are firm but
there is a growing uncertainty faced by project developers and renewable operators as to
the firmness of their grid access rights during and after their FiT support period.
Distribution connection charges are subject to a technical and financial proposal from
ERDF (or non-nationalised distributors when connection is on their local areas). However,
there is limited transparency available as to how connection charges are established in
terms of the split between shallow and deep reinforcement costs8. The exact separation
between works coming under deep vs. shallow reinforcements are not clearly assessed
and benchmarked against network development plans. Transparency of connection cost
offers is difficult to assess due to limited available of distribution investment plans at an
adequate resolution to identify network reinforcements required in the absence of
additional renewable connections.
7
ERDF manages the public electricity distribution network for 95% of continental France. The
remaining 5% are operated by 160 local electricity distribution enterprises (i.e. nonnationalised distributors). Renewable energies are principally connected to ERDF network,
and RTE’s network for a small part.
8
A ‘deep’ connection cost methodology includes the costs of local/non-shared works and
costs of wider/shared network reinforcement.
A ‘shallow’ connection cost methodology covers the costs of local/non-shared works only
and not costs of wider/shared network reinforcement.
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Figure 1 – Installed wind capacity and capacity awaiting connection by region
by mid-2013 (MW)
2,500
Wind connected
and awaiting connection (MW)….
Connected (MW)
Awaiting connection (MW)
2,000
1,500
1,000
500
0
Sources: France Energie Eolienne, ERDF
Following the Grenelle I and II laws, one key measure was the requirement for Regions9
to establish Regional Programmes for Climate, Air and Energy (SRCAE)10 whereby
they evaluate the potential for energy efficiency and renewable deployment in their region.
Within six months after the publication of the Region’s SRCAEs, the French transmission
system operator (RTE) is required to publish a Regional Programme for the
Connection of Renewable Energy to the network (S3REN) that will help meet the
objectives agreed in each regional programme11. The additional network capacity to be
developed under these programmes is then reserved for renewable projects for a period
of ten years, which represents progress for renewables compared to the previous ‘first
come, first served’ situation12. The current renewable connection framework13 allows for
an increased emphasis on cost sharing of wider network works across renewable
generators on a regional basis; with the cost of local works remaining at the charge of
generators.
9
France is divided into 27 administrative regions, of which 5 are overseas. Each Région
counts 2 to 8 Départements.
10
SRCAE stands for Schémas Régionaux du Climat, de l’Air et de l’Energie.
11
http://www.rte-france.com/fr/nos-activites/accueil-enr/schemas-regionaux-de-raccordementau-reseau-des-energies-renouvelables-s3renr
12
Loi Grenelle II – Article 68, 29 June 2010.
13
Journal Officiel, « Décret n° 2012-533 du 20 avril 2012 relatif aux schémas régionaux de
raccordement au réseau des énergies renouvelables, prévus par l’article L. 321-7 du code
de l’énergie », as amended on 4 August 2014.
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Nevertheless, there remains a degree of opacity faced by project developers with regards
to the timing, firmness and transparency for their connection charges.
Under the current price control (TURPE 3), ERDF is incentivised on quality of service for
new connections, focusing on delays for providing a connection proposal. Penalties for
delays are paid to the network users, upon request. In its 2013 report on the quality of
service provided by distribution network operators14, CRE identified that although 21% of
connection proposals were not sent within the agreed timeframe (up from 17% in 2012),
the associated penalties could be qualified as “weak” in the sense they only amounted to
a total of 450 euros because network users were not aware of the penalty mechanism.
For the next price control (TURPE 4 2014-2017), CRE will add an incentive on the
connection delay, and penalties will automatically be paid to the network users. Although
distribution network operators (both ERDF and non-nationalised distributors) will have
stronger incentives during the next price control, there remains scope for enhancement to
incentive regulation arrangements.
2.1.2
Issues faced
Implications of above are that:
§
project developers face considerable uncertainty regarding the time and cost of
connection, which slows project delivery and increases costs;
§
when operational, projects cannot rely on continued firm access to the grid15;
§
coverage of regulation and, where in existence, the strength of regulatory incentives
for network businesses to create and operate a system to deliver and support
electricity market transition are weak; and
§
access rights are granted for three years (with annual renewal), which creates
uncertainty for producers.
2.2
Recommended market design enhancements
The grid access arrangements must be improved to overcome these issues and to create
a framework that supports electricity market transition. We have the following
recommendations.
2.2.1
Grid access
The grid access arrangements must provide a more appropriate balance between the
needs of project developers and those of the network. The current process for providing
grid access follows an ‘invest then connect’ philosophy. That is, a project seeking to
connect is only granted access once necessary reinforcement works across the entire
system have been completed. Having to wait for full grid reinforcement lengthens the
timescale for securing access and reduces the degree of control that developers have
over timescales for delivery of their projects.
14
“Rapport 2013 sur la régulation incitative de la qualité de service des gestionnaires de
réseaux de gaz naturel et d’ERDF", July 2014, CRE.
15
As an example, grid operators are allowed 27 days per year (on average across the 15 years
“contrat d’achat” for onshore wind) for network maintenance. This downtime period affects
operation and has cashflow consequences for renewables operators (consequences which
will be exacerbated under future more market based RES support arrangements).
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An alternative philosophy is available. Providing grid access on a ‘connect and manage’
basis allows projects to access the system within a fixed time and/or when local
connection works are complete, rather than having to wait for full grid reinforcement. This
creates a different balance of control between project developers and the networks. It
allows developers to secure 100% financially firm access to the system at any point from
the completion of local works, offering faster and more controllable connection timescales.
The consequence of granting access before wider reinforcement is completed is that the
system operator may have to undertake more constraint resolution actions to balance the
system.
A full ‘connect and manage’ approach was adopted in 2009 in GB in response to the
substantial queue of prospective new generation, some of which had been offered
connection dates as late at 2025, that had accumulated under an ‘invest then connect’
approach. Between October 2010 and December 2013, this advanced the connection of
~1.2GW of new generation projects16. The GB model provides a possible example for
adoption of ‘connect and manage’ in France.
Full connect and manage places the responsibility for slow reinforcements on the network
operator (and ultimately other grid users) through constraint management costs. If this is
deemed inappropriate, then a softer alternative would be to guarantee full access rights
for new connections after a fixed period (e.g. 2-3 years) from application.
Securing initial grid access is the first step and ‘connect and manage’ offers clear benefits
to developers across all technologies in this regard. In addition, the nature of on-going
access rights also needs attention. Once allocated, access rights must be clearly
defined and honoured. Rights should be ‘evergreen’, lasting until notice is given by the
project developer, in order to improve certainty in relation to on-going ability to access the
system. If rights are ‘firm’, the holder should be compensated if the network is unable to
provide full access. If rights are ‘non-firm’, the circumstances under which access may
not be provided must be clearly established. Measures such as these will help to
continued and defined rights for all generators to access the grid.
2.2.2
Connections
The process for delivering connections can be enhanced. At present, connection works
are undertaken by network owners only17. The precise definition of connection works,
including technical choices upon which these are based, are neither detailed nor up for
discussion. This situation should be revised to allow effective contestability in the
provision of connection works, as is the case in other markets18. Introducing effective
contestability allows parties other than the relevant network owner to undertake
connection works, introducing competition with the potential for faster connection
timescales and/or reduced connection costs. Contestability is consistent with ensuring
network integrity, as all works need to be completed to defined standards to ensure that
necessary technical parameters and safety requirements are adhered to.
In addition to effective contestability, the basis for determining non-contested connection
charges needs attention. Connection charges should be ‘shallow’ in nature to cover
16
‘Outturn Interim Report on the Connect and Manage Regime’, National Grid, March 2014.
17
In theory, the energy code (article L342-2) allows for connection works of a generating unit to
be realised by another party than the distribution network operator.
18
In Ireland, transmission and distribution connections are contestable.
In GB, transmission and distribution connections are contestable.
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the costs of local/non-shared works only and not costs of wider/shared network
reinforcement19. This reduces a potential entry barrier for new connections across all
technology types that are currently exposed to ‘deep’ charges. Clearly, any revision to
connection charging arrangements should not alter the connection rights for existing
connectees or create potential exposure to further charges for a connection that has
already been paid for.
Furthermore, connection charges should be determined ex-ante using a transparent
methodology founded on the principle of cost reflectivity. The methodology should be
transparent, providing details of the component costs that collectively form connection
charges, and made readily available in a public document. This transparency will improve
certainty for potential connectees and also support contestability, as enhanced information
provision will improve the foundations for connection competition.
2.2.3
Network regulation
Enhanced methods of incentive regulation must be applied to all network owners /
operators to encourage them to play a full role in delivering the market transition.
Importantly, this includes extension of regulatory oversight for Distribution Network
Operators (both ERDF and non-nationalised distributors), notably with regards to
connection delays and transparency/auditability of connection offers to (renewable)
generators. This could be achieved through a greater regulatory oversight by CRE on
these issues and the introduction of more stringent incentives and penalties to ensure
competitive connection offers and timely connections. Incentives on timely and effective
connection policy should also be set by CRE, possibly based on a benchmark of
connection timing best practices in Europe. Effective regulation should encourage
network businesses to plan, invest and operate efficiently to ensure continued safe and
reliable system operation. One possible model for consideration in France is the ‘RIIO’
model for network regulation that has been developed in GB.
RIIO, which stands for Revenue = Incentives + Innovation + Outputs, has been adopted to
change the focus of network regulation towards facilitating infrastructure investment in
order to achieve environmental targets. RIIO seeks to encourage network companies to:
§
put stakeholders at the heart of their decision-making process;
§
invest efficiently to ensure continued safe and reliable services;
§
innovate to reduce network costs for current and future consumers; and
§
play a full role in delivering a low carbon economy and wider environmental
objectives.
With these objectives in mind, the RIIO framework defines primary outputs across these
categories and links revenue for the network businesses to their delivery. Primary outputs
under RIIO include customer satisfaction, reliability and availability, safe network services,
connection terms and environmental impact. If the network business over-delivers against
the outputs, its revenue increases, while under-delivery results in lower revenue.
Therefore, the focus under RIIO is on setting a framework for delivering required outputs
backed by incentives (rewards and penalties), rather than defining inputs. Network
operators have a long price control period (eight years) and within this period have
freedom to balance Capex and Opex measures to deliver the agreed outputs.
19
Shallow connection charges for generation exist in European markets including GB,
Germany, Netherlands and Spain (See: ‘Review of International Models of Transmission
Charging Arrangements’, CEPA, 2011).
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By defining appropriate output measures with associated rewards/penalties, the
model of network regulation in France could be enhanced to support the market
transition and better align the interests of the network businesses with those of
system users. One incentive could focus upon the cost of constraint management, which
ties back to recommendations for some form of connect and manage approach to grid
access, which may give rise to increased constraint costs.
In tandem, the process for forward looking network planning can be enhanced by setting a
longer-term incentive regime to support strategic planning and improving transparency of
planned / potential works and increasing stakeholder involvement through a more
consultative process allowing project developments within areas where connection could
be progressed more easily, as these would be part of network reinforcements plans. This
will provide a clearer route for network users to feed in information regarding their own
requirements which can enhance the network planning and development process. It also
increases general awareness of possible pathways for future network development that
can help to inform generation project development plans. This type of process was
adopted by EirGrid, the Irish TSO, in its Grid25 process20. The aim of Grid25 was to
provide a common understanding of how the development of the grid should be
undertaken to support a long-term sustainable and reliable electricity supply.
20
http://www.eirgrid.com/transmission/investinginthefuture-grid25/
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3.
WHOLESALE MARKET
Access to liquid wholesale markets is a key feature of well-functioning and competitive
electricity markets as it allows market participants (especially independent players) to
adjust and match their physical and commercial positions to manage their price and
volume risk exposure. Liquidity is also required across various product timeframes (from
year ahead to intra-day) to provide the ability to manage risk exposure. Liquidity does not
appear on its own. It often relies on a significant degree of transparency on market
fundamentals underlining market participants’ views.
With regards to market design enhancements measures, we focus our attention upon the
following issues:
§
routes to market for renewable generators outside the FiT support period;
§
need for new products; and
§
production transparency (forecast and out-turns).
3.1
Current situation
3.1.1
Context in France
The trading and commercial arrangements in the French wholesale electricity market can
be characterised by the following elements:
§
regulated access to EDF’s historic nuclear baseload generation (ARENH);
§
forwards and futures markets, that allow bilateral contracts for electricity to be struck
up to several years ahead;
§
short-term ‘spot’ power exchanges (daily auctions and continuous intra-day markets),
enabling participants to ‘fine-tune’ their contracts up until one hour before real time 21;
§
a Balancing Mechanism in which the French TSO (RTE) accepts offers and bids for
electricity to enable it to balance the transmission system; and
§
a settlement process for charging participants whose contracted positions do not
match their metered volumes of electricity, for the settlement of accepted Balancing
Mechanism offers and bids.
Electricity is traded via either Over The Counter (OTC) transactions, which are
characterised by bilateral contracts or contracts matched on brokers’ platforms for both
forwards and spot plus the EPEX Spot (European Power Exchange) for spot (day-ahead
and intraday). In addition, the EEX Power Derivatives exchange exists for futures
products (i.e. relating to long-term contracts to be fulfilled at a future date in up to several
years’ time).
OTC transactions represent around 80% of wholesale electricity deliveries in France and
are mainly baseload products. In 2012, 284.7TWh were actually physically delivered
following OTC transactions (excluding ARENH)22.
21
Gate Closure is the time by which all notifications must be given; currently it is set at 1 hour
prior to the start of the traded period.
22
CRE. ‘Observatoire des marchés’, Q1, Q2, Q3 and Q4 2012.
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As shown in Figure 2, since a peak of 754TWh traded in 2009, volumes have
subsequently decreased due to the economic downturn and the ability for suppliers to
access 100TWh of EDF’s baseload nuclear electricity under the ARENH. The volumes
linked to the ARENH are traded, but via a separate more administered route than other
wholesale power trades. This differentiated approach fragments wholesale trading
activity, with potential implications for liquidity and price discovery in the wider market.
Excluding the ARENH, trades are generally concentrated around Year+1 to Year+3
products. Since 2008, day-ahead liquidity has been relatively stable at around 15% of the
annual electricity demand. However, liquidity in other products, and especially intraday, is
very limited and therefore constitutes a barrier to effective and adequate short-term
hedging capability for market participants.
Figure 2 – Overview of products traded volumes on organised exchanges
and intermediated OTC markets
Volumes of products traded on organised exchanges….
and intermediated OTC (TWh)….
300
Intraday
Day-Ahead
Week-End
Week
Month
Quarter
Annual
250
Total 2008:
656TWh
Total 2009:
754TWh
Total 2010:
698TWh
Total 2011:
694TWh
Total 2012:
576TWh
200
150
100
50
0
2008
2009
2010
2011
2012
Sources: Pöyry Management Consulting analysis based on CRE and RTE data.
3.1.2
Issues faced
Implications of above are that:
§
short-term liquidity is mostly concentrated in the day-ahead auction with limited
intraday liquidity, which limits full and adequate hedging possibility and market risk
exposure management;
§
liquidity and product range is limited on centralised exchange platforms (i.e. liquidity
on forwards is almost all OTC and options are only traded OTC); and
§
limited trading products and trading routes would be available to renewables
operators after the support period.
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3.2
Recommended market design enhancements
As existing renewable projects come out of the FiT arrangements and new projects
commission under future RES support arrangements, it is essential that there are
appropriate routes to market for generation output. Furthermore, the need for flexibility is
growing, and trading must move closer to real time in response to weather forecast error.
Market players now face a potent combination of price and volume risk which cannot
easily be hedged with standard traded products. Products need to develop to match the
evolving requirements of market participants. We have the following recommendations.
3.2.1
Traded products
The traded market needs to offer a broad range of products to meet the requirements of
market participants, with depth and liquidity across the spectrum. Improving liquidity and
offerings in the intraday window are particularly important to allow fine-tuning of positions
as intermittent generation increases and demand side flexibility becomes more prominent.
But even in the latest market coupling arrangements23, emphasis is given to day-ahead at
the expense of intraday, when sharing of capacity between the different timeframes is
required. The price for intraday capacity on interconnectors (which should value cross
border intraday flexibility) is effectively zero, which could block the build of new
interconnection. Under these market arrangements, flexibility will continue to be
undervalued, and cannot easily be traded between countries. The arrangements for
continuous intraday capacity allocation under the Target Model must be improved,
therefore. Market coupling rules should allocate cross-zonal capacity across timeframes
based on market values not a priori reservations, and should provide a way of pricing
intraday capacity.
To supplement this, internal intraday auctions should be developed, alongside
coupled continuous trading, to support development of liquidity in this timeframe. The
products offered intraday should include 30 minute blocks so that it is possible to trade at
a granularity that matches settlement period duration. As an example, EPEX Spot
announced it will launch such an intraday auction for Germany in Q4 201424.
Across the traded product spectrum, market designs should support trading of energy
options between market participants (including as insurance against imbalance). Options
are currently only traded OTC. Trading of options could be enhanced by making option
products available through centralised market platforms, rather than OTC.
3.2.2
Routes to market
Parties seeking to trade wholesale power have various route-to-market options. These
range from a self-trading via an in-house trading desk through to long-term Power
Purchase Agreements (PPAs) with wholesale market players (licensed electricity
suppliers, aggregators, etc.). PPAs tend to be the most common approach for
independent producers in many markets.
An option is to develop arrangements for an off-taker of last resort, at least as a
transitional measure, to provide a backstop contractual option while commercial off-take
23
https://www.epexspot.com/document/25834/2014-02-04_NWE_GoLive_Communication_NWE_PCR_SWE.pdf
24
https://www.epexspot.com/document/27641/EPEX%20SPOT_EEXWorkshop_05062014.pdf, page 15
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arrangements are developing. A similar concept is being developed in GB to provide
independent renewable generators with a guaranteed ‘backstop’ route-to-market at a
specified discount to the market price25 and also in France in the context of injected biomethane contracts. If adopted, the backstop arrangements should be designed with the
goal of supporting the development of competition in this area and should not frustrate this
ambition.
3.2.3
Transparency
Effective functioning of the wholesale market can be improved by enhanced information
transparency. As required under REMIT 26, production data provision for generation
capacity that has ‘significant influence on the market’ helps in this regard. This principle
should embrace both renewable and non-renewable technologies. Production forecast
and outturn information should be made available to the market at transmission
and distribution levels aggregated by technology type to support market operation.
This is particularly important for wind and solar especially given the potential for variations
between anticipated and actual output depending upon weather conditions.
3.2.4
REGO market
The architecture of the Renewable Energy Guarantee of Origin (REGO) arrangements
already exists, but more can be made of this to allow the value of green energy to emerge
and be realised. To support this, a centralised marketplace for trading of REGOs
could be established. Developing the REGO market in this manner could act as a
complement to support mechanisms, as a basis for dedicated ‘green’ energy supply to
customers.
25
https://www.gov.uk/government/groups/electricity-market-reform-off-taker-of-last-resortadvisory-group
26
REMIT: Regulation on Energy Market Integrity and Transparency.
EU directive in effect since December 2011 and aiming at prohibiting insider trading, and
enhancing trading and physical transparency in energy markets.
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4.
IMBALANCE ARRANGEMENTS
Imbalance settlement (or ‘cashout’) arrangements are a vital part of wholesale trading
arrangements, providing the route for commercially settling differences between physical
and contractual positions. In carrying out this function, the cashout arrangements also
influence imbalance exposure risk and provide financial incentives to balance.
Making ‘Balance Responsibility’ universally applicable is a key element of the Target
Model27. Combined with the requirement for cost-reflective imbalance prices, it is
designed to incentivise market participants to pay much greater attention to balancing
their own position in market timeframes, rather than relying on the Transmission System
Operator (TSO).
FiT supported renewable generators do not currently bear imbalance risk exposure, as it
is transferred to the off-taker. But this will have to change for future projects developed
under revised RES support schemes to ensure compliance with the EU Target Model and
State Aid requirements for future RES support schemes, both of which require Balance
Responsibility for all technologies28. This makes the design of the imbalance
arrangements an important issue for current installations post FiT and future projects and
there are several areas where enhancements can be made:
§
imbalance price structure; and
§
timescales linked to settlement.
4.1
Current situation
4.1.1
Context in France
The imbalance arrangements financially settle any deviations between physical and
contractual positions. If generators generate less energy than they have sold through
contracts or suppliers consume more energy than they have bought, this shortfall is paid
for through imbalance pricing. Similarly, if generators produce more energy than they
have sold or suppliers consume less than they have purchased, this spill receives
payment. In France, these imbalance arrangements are applied at a portfolio level.
In France, gate closure for trade nominations occurs one hour before the start of the
relevant settlement period. The settlement period over which imbalance positions (and
associated costs) are assessed is 30 minutes. With the exception of renewable
generators under FiT29, all types of generation (production, load, pumped storage) are,
therefore, financially incentivised to be balanced at a half-hourly aggregation. The
imbalance settlement structure works on the basis of a dual price whereby the imbalance
27
The implementation of the European Electricity Target Model is an important part of the
delivery of the single European market. The Target Model has been developed to provide a
pan-European framework for the allocation and use of transmission capacity between pricing
zones. Therefore, it defines rules for the integration of electricity markets in four timeframes
– forward, day-ahead, intraday and balancing. In addition, it also sets rules in relation to
imbalance pricing, which has a knock-on impact on trading in earlier timeframes.
28
However, neither the EC State Aid Guidelines nor the EU Target Model prevent future RES
support regimes from allowing recovery of imbalance costs through some measure.
29
Renewable generators under FiT do not bear the imbalance exposure risk as it is transferred
to the off-taker (“Acheteur Obligé”) via the “Obligation d’Achat”.
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price is a function of the direction of the deviation and its relativity to the overall position of
the system. This means that long and short imbalance volumes are cashed out on a
different basis. Imbalance settlement prices for an imbalance in the same direction as the
system imbalance are calculated as a weighted average of the various balancing actions
taken by RTE to maintain balance across every settlement period, adjusted by an
incentive coefficient “K”. The value of K has been fixed at 0.08 since 1 July 2011. An
imbalance in the opposite direction to the system imbalance is cashed out at the EPEX
day-ahead spot price.
The imbalance dual pricing structure is shown in Table 3. When the system is short,
market participants that are short will be charged the Weighted Average Price of Upwards
Balancing Actions x (1+K) whereas market participants with a long position will receive the
Epex Spot day-ahead price. Conversely, when the system is long, short market
participants receive the Epex Spot day-ahead price while long market participants are
charged the Weighted Average Price of Downwards Balancing Actions / (1+K).
Table 3 – French imbalance price structure
Participants \ System
Short
Long
Long
Epex Spot day-ahead price
Weighted Average Price of
Downwards Balancing
Actions / (1+K)*
Short
Weighted Average Price of
Upwards Balancing Actions x
(1+K)**
Epex Spot day-ahead price
* With Epex Spot price acting as an upper limit
** With Epex Spot price being a floor
Source: RTE
The evolution of the Weighted Average Price of Upwards and Downward Balancing
Actions relative to the Epex Spot day-ahead prices since April 2003 is illustrated in Figure
330. Over time, the spread between the balancing action prices (both upwards and
downward) relative to the day-ahead price has been narrowing but volatility has remained.
30
Please note that the Weighted Average Prices of Balancing Actions are different from the
imbalance prices.
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Figure 3 – Evolution of Weighted Average Price of Upwards and Downwards
Balancing Actions relative to the Epex Spot day-ahead
(€/MWh, nominal money)
Weighted average upward price relative to Epex Spot day-ahead
Weighted average downward price relative to Epex Spot day-ahead
Epex Spot day-ahead relative value
40
30
20
10
0
-10
-20
Apr-13
Oct-12
Apr-12
Oct-11
Apr-11
Oct-10
Apr-10
Oct-09
Apr-09
Oct-08
Apr-08
Oct-07
Apr-07
Oct-06
Apr-06
Oct-05
Apr-05
Oct-04
Apr-04
-40
Oct-03
-30
Apr-03
Weighted average price of balancing actions (upwards and
downwards) relative to the Epex Spot day-ahead price
(€/MWh, nominal money)
50
Sources: RTE, Powernext, Reuters, Pöyry Management Consulting analysis
Figure 4 presents an evolution of imbalance settlement prices since April 2003; averaged
at a monthly resolution. Average imbalance prices (in nominal terms) in 2012 were
€37.7/MWh for positive imbalance and €54.7/MWh for negative imbalance. Imbalance
prices are volatile and closely linked to the Epex spot day-ahead price. The spread
around it has been decreasing over time.
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Figure 4 – Monthly average imbalance settlement prices compared to monthly
average Powernext/EPEX day-ahead price (nominal prices, €/MWh)
140
Negative settlement price
€/MWh, nominal money….
120
Average EPEX price
Positive settlement price
100
80
60
40
20
0
Sources: RTE, Powernext, Reuters, Pöyry Management Consulting analysis
4.1.2
Issues faced
Implications of above are that:
§
FiT supported renewable generators are not subject to imbalance exposure, but
Balancing Responsibility means that this will not be the case for current installations
when the FiT support ends and future projects, increasing the importance of the
imbalance settlement arrangements going forward;
§
a dual imbalance price structure has particular implications for cashout exposure
faced by autonomous generators, such as wind;
§
imbalance settlement periods are currently shorter than wholesale trading products
currently available to market participants, which limits the capability and opportunity
for self-balancing a 30 minute granularity; and
§
contractual trade nominations one hour before real time may not enable latest
forecast positions to be covered through trade activity.
4.2
Recommended market design enhancements
The principle of Balance Responsibility is accepted as the basis for future market design
and is supported as an important step for full integration of renewable generators into the
market. Taking this is a pre-requisite for future imbalance arrangements, we have the
following recommendations.
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4.2.1
Imbalance price structure
The current dual cashout pricing arrangements place different value on imbalances in
opposing directions within the same settlement period.
In a period with a net short position, parties with a short position must pay a higher
imbalance price than parties with a long position receive. Similarly, in a period with a net
long position, parties with a long position receive a lower imbalance price than parties with
a short position pay. Therefore, imbalances in the opposite direction to that of the system
that are helping to reduce the net imbalance position are not valued in line with their
balancing value to the system. This is illustrated in Figure 5.
Figure 5 – Dual imbalance price structure effects
€/MWh
Overcharged
‘shortfall’
Under-paid
‘length’
Party
Short
System
Long
Short
Short
Long
Long
This has a particular relevance for autonomous generation, which may under-contract in
the day-ahead market to reflect potential forecast error, and so carry a long imbalance
position into settlement. If the system is short, remunerating this long imbalance at the
EPEX day-ahead price (as under the current dual pricing system) undervalues the positive
effect that it has on the system position. Non-autonomous generation can more readily go
into gate closure with a balanced position and capture the value of upward generation
through the balancing market.
The value of imbalance positions in the opposite direction to the system can be
acknowledged by switching from a dual to a single imbalance price structure, with
the single price based on the cost of resolving imbalances in the same direction as the net
system imbalance. Under a single pricing approach, imbalances are valued consistently
regardless of their direction. This ensures that imbalances in the opposite direction to the
system imbalance are cashed out at their balancing value to the system. The effects are
shown in Figure 6. In addition to reducing imbalance risk exposure, removing the
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imbalance price spread also simplifies the cashout arrangements which may reduce
barriers to entry.
Looking to other markets for reference, there is evidence of single imbalance price
arrangements. Single imbalance price arrangements already exist in Germany, are being
developed in GB and are being considered in Ireland.
Figure 6 – Single imbalance price structure effects
€/MWh
Consistent
value
Consistent
value
Party
Short
System
Long
Short
Short
Long
Long
The Target Model makes no specification of whether single or dual pricing is required but
it is in favour of more marginal imbalance pricing. This comes through the combined
requirements for (a) for imbalance prices to be based on the weighted average price of
energy balancing actions and (b) energy balancing prices to be pay-as-clear. Taken
together, this tends to a requirement for marginal imbalance pricing. Any move towards
more marginal imbalance pricing should be contingent on the availability of
appropriate tools to manage this imbalance risk.
4.2.2
Timings
The Target Model has a working assumption of a harmonised imbalance settlement
period duration of no longer than 30 minutes. This is consistent with the current system in
France, where settlement periods are 30 minutes long. Other markets already have
shorter settlement periods, including Germany, Belgium and the Netherlands where the
duration is 15 minutes. This creates the potential for cross-border trading of shorter
blocks, if desired. However, there is no particular need to shorten the settlement period in
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France31. There is a need, however, for wholesale trading products to be available on
a half-hourly basis so that parties are able to trade at a granularity that matches the 30
minute settlement period. It is problematic for all parties, but those with variable
generation sources in particular, that it is not possible to shape contractual positions down
to the half-hourly level when this is the timeframe for settlement.
A more pressing issue relates to the timing of contractual gate closure. Gate closure for
trade nominations should be reduced from 1 hour to 30 minutes or even 15 minutes
ahead of real time. This would allow for improved forecasts of likely outturn which can
then be backed by trading activity closer to real time, thereby allowing a reduction of
imbalance risk. This requires associated improvements in intraday trading options, as
discussed in Section 3.
An alternative option as part of the transition to single imbalance pricing is to allow ex-post
trade nominations or re-nominations of internal trades. This enables parties with
countervailing imbalance positions to offset individual imbalance exposure. Ex-post
arrangements are possible in other markets. On the TenneT systems in the Netherlands
and Germany, ex-post nominations are allowed until D+1 at 10:00, while in Belgium expost nominations are possible until D+1 at 14:00. Ex-post re-nomination does not
adversely affect security of supply as physical nominations are still submitted at gate
closure and the TSO still manages the net imbalance position in the balancing window.
Altering contractual imbalance positions after the event does not alter management of the
system in real-time and contractual nominations are not directly connected to physical
nominations to the TSO.
31
In any event, settlement period duration should be set in multiples of 10 minutes, given that
this is the granularity of generation metering.
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5.
RES SUPPORT
Deployment of renewable generation has increased in France since 2000, aided
principally by a renewable support scheme based on a Feed-in Tariff backed by a
purchase obligation to ensure a route to market. However, the current FiT support
scheme for renewables is not expected to endure. This requirement is stipulated by the
European Commission, whose State Aid guidelines32 require that supported renewable
generators sell directly into the market and are subject to market obligations.
New RES support arrangements for future projects must change to be compatible with
these requirements. Clearly, however, existing projects under the current support scheme
should be permitted to continue to operate within these arrangements for the remainder of
the defined support period to avoid retrospective change and the destabilising effect that
this can have on future investors33. Therefore, it is vital that retrospective changes are not
made, which would undermine confidence, and that the existing FiT is grandfathered for
projects developed under it. Revisions to the future scheme should not alter the support
afforded to projects under the existing FiT34.
In the context of future RES support arrangements, we focus our attention upon:
§
RES support format;
§
RES support allocation and pricing.
5.1
Current situation
5.1.1
Context in France
Growth in the development of renewable electricity in France is the result of national
policy drivers including the two main support schemes for renewables, the Purchase
Obligation and the Call for Tenders. Both of these schemes were set up in 200035, in
response to the EU Directive of 1996 on Common Rules for Electricity Markets36. More
recently, national policy on renewables has evolved as part of a wider reflection on
biodiversity conservation, climate change mitigation and air quality issues, under the socalled ‘Grenelle de l’Environnement’, although the EU Renewable Energy Directive of
2009 and its associated renewable targets is likely to be the biggest influence on national
renewables policy until 2020. Due to its extensive hydroelectric facilities, France
produced around 16% of its energy from renewable sources in 2012.
32
Guidelines on State aid for environmental protection and energy 2014-2020 (2014/C
200/01).
33
However, existing RES onshore wind generators are given the option to opt-out the FiT
“contrat d’achat” and switch to market based revenues (or new support arrangements when
those are in place), subject to the penalty clause (XIII-6) specified in the latest contracts
(“Contrat d'achat de l'énergie électrique produite par les installations utilisant l’énergie
mécanique du vent et bénéficiant de l’obligation d’achat d’électricité” adopted on 30 July
2014) and the payment of an exit fee.
34
It may be worth considering giving projects under the existing support scheme the choice to
switch to an amended support scheme at their discretion.
35
Loi 2000-108: ‘Loi Relative à la Modernisation et au Développement du Service Public de
L’Electricité’, 10 Février 2000.
36
EU Directive 1996/92/EC, Official Journal of the European Union.
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Wind energy is a major renewable generation technology ranking second in installed
capacity after hydro in France expected to provide most of the renewable energy
generation growth in order to meet France’s 2020 targets. A graph of installed capacity
(cumulative and annual) at the end of 2012 is provided in Figure 7. Onshore wind
capacity grew at a rate around 1GW/year with the implementation of the Feed-in Tariff in
2006, and generation levels increased from 2.3TWh in 2006 to 14.9TWh in 2012.
Figure 7 – Installed wind capacity (1999-2012)
8,000
7449
Total installed wind capacity (MW)
Wind capacity (MW)
7,000
6692
Annual increase in installed wind capacity (MW)
6,000
5764
5,000
4574
4,000
3327.0
3,000
2250
2,000
1502
1,000
0
21.2
61
1999 2000
94
129
2001 2002
752
359
219
393
2003
2004 2005
750
2006
748
1077
2007 2008
1247
2009
1190
928
2010 2011
757
2012
Source: RTE
The primary measure implemented to stimulate the development of renewable capacity is
via a Feed-in Tariff and through a Purchase Obligation. The Obligation is set on
Electricité de France (EDF) and on local electricity distributors where renewable
generators are directly connected to the distribution network. In turn, EDF and the local
electricity distributors recover the extra cost of purchasing electricity from renewable
generators under these contracts through a levy imposed on all electricity consumers, the
CSPE (‘Contribution au Service Public de l’Electricité’) 37.
The level of the Feed-in Tariffs and the duration over which these are paid for the different
renewable technologies are set by Government decrees and orders. The Purchase
Obligation has evolved in line with market developments to ensure that the targeted
technologies receive an appropriate support. Under the Purchase Obligation, eligible
renewable generators are paid a fixed price for every kWh of electricity fed onto the grid,
for a fixed period of time. The use of a fixed Feed-in Tariff enables renewable generators
to avoid exposure to variations in electricity prices over the duration of their contract. The
Feed-in Tariffs are set by the French Government after consultation with the French
regulator CRE.
Feed-in Tariffs provide ex-ante certainty to investors on the support level receivable per
MWh produced but also create an incentive for generators to produce independently of
the market price. FiT supported technologies currently receive support even during
negative wholesale electricity price periods.
The FiT support is for projects from the start of their commercial operation, although
projects that have already generated electricity and entered commercial off-take
37
The CSPE covers the cost of the Purchase Obligation for renewables under a FiT but also
includes national perequation of tariffs, social actions, etc.
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agreements are also eligible under specific circumstances38; in addition to upgraded or
refurbished hydro, waste-to-energy and CHP projects. Once the FiT and the Purchase
Obligation support period ends, renewable generators will have to sell their electricity on
the wholesale market.
On 18 June 2014, the French Energy Minister presented the energy transition draft law
drawing upon a lengthy consultation process with experts and stakeholders. Along with
ambitious renewable electricity targets for 2030 (renewable electricity share to reach
40%), evolutions to the current FiT support scheme for renewables is also being
envisaged towards a more market based type of support.
5.1.2
Issues faced
Implications of above are that:
§
FiT support renewables are shielded from market exposure (and the impacts of
intermittent low/zero marginal costs);
§
FiT supported renewables have incentives to run no matter what the market
conditions are (i.e. negative prices) as they receive a per MWh payment; and
§
any changes to the FiT support system will need to comply with the recently approved
State Aid Guidelines, which will have substantial impacts on support design.
5.2
Recommended market design enhancements
Once the required reforms to integrate RES into the electricity market are in place, the
future RES support arrangements need to become more market-based to comply with the
EC State Aid guidelines. With this backdrop, we have the following recommendations.
5.2.1
RES support format
The EC State Aid guidelines require that support is provided as a premium in addition to
the market price and that the generator sells its electricity directly in the market. So it is
clear that supported generators will need to secure a route to market in order to capture
wholesale revenue, with a premium then available to provide additional revenue.
There is scope for the premium to be either variable or fixed in nature:
§
Variable premium: premium varies depending upon the relativity of the wholesale
price to a pre-defined support level needed by the generator.
§
Fixed premium: premium is a pre-defined top-up payment to the generator, with no
reference to the wholesale price.
Each approach has different merits. Under a fixed premium scheme, renewables are fully
exposed to the underlying market prices and the level of additional support is known in
advance. But supported generators are exposed to market risks that are outside their
influence, with associated risk premiums for projects. Conversely, a variable premium
approach limits the exposure of renewable generators to movements in wholesale market
38
For upgraded or refurbished projects whose average annual generation increases by less
than 10%, a new purchase obligation contract is signed to cover the extra generation. The
duration of the contract is for the whole duration allowed for that technology and, in the case
of hydro where there tariffs vary by project size, the tariff applicable for that new contract is
that of the revised project size.
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prices, while providing greater certainty to investors and operators in terms of potential
revenue streams, but with less predictable costs of support.
A variable premium approach could follow the ‘Contract for Difference’ (CfD) FiT model
that has been developed in GB and recently been given State Aid clearance by the EC
under the latest guidelines39. Under the CfD FiT approach, support is paid out as a
variable premium based on the difference between a reference wholesale price and a
defined strike price. Supported generators need to sell output into the wholesale market
to capture wholesale revenue and are responsible for any imbalance risks. The GB model
allows for 2-way difference payments. A premium is paid to a generator when the
reference wholesale price (taken from the day-ahead market for intermittent technologies)
is below the strike price40. If the reference wholesale price is above the strike price, the
difference payment flows from the generator such that its revenues are capped at the
strike price (assuming it captures the wholesale reference price for its output).
This approach improves certainty for investors. It provides transparency of anticipated
revenue ex ante and limits exposure to variations in wholesale prices. Supported
generators must still interact with the market, however, given reliance on market revenue
within overall revenue stream. In addition, as support payments diminish with higher
wholesale prices and difference payments may even flow from the generator, this
approach can be attractive from a public acceptance perspective. Overall, the variable
premium has the effect of giving a guaranteed price for each MWh of production, with
some risk based on the difference between the reference market price (day-ahead for
wind) and the actual price achieved by the generator in its trading41.
The fixed premium approach is a more simplistic approach from an implementation and
administrative perspective, based on a pre-defined support payment to generators and
associated payment flows. Generators still rely on capturing wholesale market revenue
by selling their output into the market, but the level of support is invariant to the actual
wholesale price. This can create a perception of ‘windfall gains’ to the generator in the
event of high wholesale prices as the upside accrues to the supported generator. The
contrary is also true, however, as generators face downside risk in the event of low
wholesale prices. Indeed, generators under a fixed premium are exposed to market risks
that are outside their control, with associated risk exposure. The implication is that there
is less certainty for investors in terms of total revenue streams, which can increase cost of
39
http://europa.eu/rapid/press-release_IP-14-866_en.htm
40
An additional feature is that no support will be paid in case of periods of negative prices
longer than six hours.
41
The level of basis risk will vary depending upon a generator’s ability to capture the relevant
wholesale reference price:
·
if a generator sells its output at a price higher than the reference price (i.e. it beats the
market), then it can capture upside;
·
if a generator sells its output at the reference price (i.e. it matches the market), then it
faces neither upside nor downside; and
·
if a generator sells its output at a price lower than the reference price (i.e. it is beaten by
the market), then it faces downside.
The ability for a generator to capture the market price is influenced by its trading approach.
If the generator sells through a PPA with a discounted price, then its capture price is likely to
be lower than for a generator whose output is self-traded. But in both cases, variations in
the supply-demand position between the reference price period and real-time will create the
potential for basis risk.
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capital requirements42 and, hence the overall financial level of support required to
progress a project. Certainty can be improved by setting a cap and/or floor for the overall
revenue stream (wholesale revenue plus support), thereby providing a band within which
anticipated revenue streams are likely to fall and setting constraints on potential support
payment costs. Nevertheless, exposure to market risks remains a feature of a fixed
premium approach.
A variable premium approach based on a 2-way CfD FiT and a fixed premium model are
both illustrated in Figure 8.
Figure 8 – Variable and premium support illustration
On balance, our recommendation is that future RES support arrangements in France
should be based on a variable premium approach. The fixed premium approach
exposes RES to energy market prices which are determined by drivers beyond the control
of the generators, which carries risk and an associated risk premium that increases the
cost of projects. A variable premium limits the exposure of renewable generators to
movements in wholesale market prices, providing greater certainty to investors and
operators in terms of potential revenue streams. It does still require market interaction,
42
During the development of its Electricity Market Reform proposals, analysis commissioned
by DECC suggested that hurdle rates for onshore wind in GB are:
·
0.3% lower under either a fixed FiT or a CfD FiT compared to a premium FiT for a typical
utility;
·
1.4% or 1.1% lower under a fixed FiT or a CfD FiT respectively compared to a premium
FiT for an independent developer.
‘Electricity Market Reform’, Consultation Document’, DECC, December 2010.
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however, given the need for projects to secure wholesale market revenue streams. While
the support cost is variable, overall costs to consumers can be managed through
application of a cost control mechanism, as discussed below. This type of scheme has
already gained State Aid approval in GB, as mentioned above.
Under a variable premium approach, the basis for defining the strike price and the
wholesale market reference price are important design factors. The basis for setting strike
prices is related to the allocation process, which is discussed in Section 5.2.2. The
wholesale market reference price should be defined to suit the operating characteristics
and risks of different technologies, as well as liquidity of trade in different product
windows. For wind in France, selection of a day-ahead reference price appears
appropriate given dependence of generation output on meteorological conditions for which
forecasting certainty improves closer to real-time and reasonable depth in day-ahead
trading activity.
To comply with State Aid guidelines, measures should be put in place to ensure that the
support arrangements do not create incentives to generate electricity under negative
prices. This is in response to concerns that production based support schemes create
incentives for low/zero short-run marginal cost (SRMC) generators to offer negative bid
prices in order to run and so receive support payments, creating artificial negative prices
which distort short-term dispatch efficiency and price formation. The EC’s recent approval
of the GB CfD FiT scheme specifically referenced that under the arrangements, as of
2016, no support will be paid in case of periods of negative prices longer than six hours43.
This aspect of the GB arrangements is specifically intended to address the potential for
incentives to generate in periods with negative prices. In Germany, the market premium
paid to renewable generators is also calculated in way to not over reward controllable
renewable technologies (such as wind and solar) by incentivising them not to run during
negative price periods. To be consistent with State Aid guidelines, the proposed variable
premium approach should, therefore, be combined with a mechanism to limit support
paid to zero SRMC generation in periods of negative wholesale prices. This will
address concerns regarding incentives to bid negatively and so mitigate the potential for
distortionary effects44.
To manage, budget implications and costs to consumers, and therefore to create a more
stable long term regime for renewable generators, it will be necessary to set a cost
control mechanism. This mechanism should operate with reference to the overall cost
to consumers, rather than being tied to support costs explicitly. The rationale for this is
that it is the aggregate price of electricity that is relevant to consumers rather than the
support cost sub-component, which will vary depending upon underlying commodity
prices. The mechanism should be based around a forward looking view of end-user
prices (which may be expressed within a range), developed through dialogue with
stakeholders. Commitment to provide RES support can then flex to reflect wholesale
price variations within the overall anticipated consumer price trajectory. This provides a
more flexible method of managing support costs than a hard limit on support costs in
isolation.
43
http://europa.eu/rapid/press-release_IP-14-866_en.htm
44
Consideration will need to be given to any equivalent arrangements for non-zero SRMC
renewable projects, such as biomass.
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5.2.2
RES support allocation and pricing
The desire to make RES support payments more market-based also extends to their
allocation. The State Aid guidelines require that, from 1 January 2017, support is
allocated in a competitive bidding process unless certain criteria apply including:
§
limited eligibility;
§
demonstration that competitive bidding would lead to higher support levels; or
§
demonstration that competitive bidding would result in low project realisation rates.
The ultimate goal for an enduring system is based upon a competitive auction or
tender process, when conditions for effective competition are met (which is not the
case now).
But this is not a practical option in France in the near-term. As things stand, a competitive
bidding process is likely to result in higher levels of required support and/or low project
realisation due to risk premiums created by uncertainty and timeframes linked to the
current planning and grid access arrangements. Until these arrangements are
enhanced and greater certainty is available for developers, competitive bidding is
not appropriate.
Instead, as a transitional measure, allocation should be determined through an
administrative process, with technology banding to allow participation from
different technologies. The support price can be set to reflect the estimated pay-asclear price for the relevant band, based on assessment by a central body. The transitional
process should be time bound, with the duration based on assessment of the likely time
needed to address barriers to competitive bidding (i.e. limited eligibility or potential for
competitive bidding to result in higher support levels or lower project realisation, as
identified in the State Aid guidelines). This transitional, administrative process provides a
bridge between the current FiT scheme and market-based support in future.
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6.
RETAIL
While the generation mix is changing as the penetration of renewable technologies, such
as wind and solar, increases, electricity demand and the retail sector are also evolving.
Greater electrification of heat and transport will increase overall demand, while the
advance of ‘smart’ technologies has the potential to change patterns of consumption and
allow enhanced integration of the demand side into the market, helping to balance
production intermittency. The public perception of the value of green energy is also key to
the development of renewable production. Where consumers may attach a premium to
green energy, retailers should be able to reflect this in their offerings and to drive a
demand for REGOs to back up their green supplies.
We focus our attention upon the following:
§
realising ‘green’ value; and
§
smart metering and demand side management.
6.1
Current situation
6.1.1
Context in France
Liberalisation of the French market has been completed in several phases with all
customers free to choose their supplier since 1 July 2007. Figure 9 shows the evolution of
customers (domestic and non-domestic) switching to market based tariffs in the French
retail electricity market. Liberalisation had been slow to start in the domestic segment, but
is now on a continuous growing trend as shown by the increasing market share of
independent suppliers. According to CRE, at the end of June 2013, a total of 2.28 million
households (out of 31 millions) had switched to non-regulated tariffs, of which less than
0.5% had remained with their historical supplier45.
Figure 9 – Evolution of customer switching to market based tariffs
Non-domestic electricity market
10%
2.5
0.8
8%
7%
0.7
6%
0.6
5%
0.5
4%
0.4
3%
0.3
0.2
2%
0.1
1%
0.0
0%
Customers having exercised their eligibility .
(million) .
Independent supplier market share for non-domestic customers
9%
Independent supplier market share .
Customers having exercised their eligibility .
(million) .
0.9
Number of non-domestic customers supplied by EDF
8%
Number of domestic customers supplied by other independent company
Number of non-domestic customers supplied by other independent company
1.0
Number of domestic customers supplied by EDF
7%
Independent supplier market share for domestic customers
2.0
6%
5%
1.5
4%
1.0
3%
2%
Independent supplier market share .
1.1
Domestic electricity market
0.5
1%
0.0
0%
Source: CRE
45
e
CRE, ‘Observatoire des marchés de l’électricité et du gaz – 2 trimestre 2013’, Q2 2013.
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EDF’s regulated tariffs for small commercial and industrial customers will be abolished by
the end of 2015, with residential regulated tariffs remaining available.
As the retail market is still heavily bound to regulated tariffs, the development of innovative
offers from the utilities (including green energy and dynamic price offerings) is limited.
§
green value is not yet perceived by final customers. The CSPE, which recovers
mainly the costs of FiT for renewables, and “péréquation tarifaire” with overseas
regions, is paid by all customers and is either not considered or seen as a growing
cost on the bill; and
§
a small number of dynamic price offerings are in place for some contracts, including
regulated ones (heures pleines/heures creuses), but demand side services in which
consumers can respond to dynamic market prices are embryonic.
6.1.2
Issues faced
Implications of above are that:
§
Currently, limited opportunities exist for renewable generators to market their
electricity at the supply level and could prove to be problematic when large numbers
of installations come out of FiT support or when changes are made to the support
scheme for a more market based type solution.
§
Demand side management and dynamic pricing is currently limited and therefore
prevents customers from responding to the market and providing flexibility to it.
6.2
Recommended market design enhancements
The value that consumers place on green energy is currently untested. Separately, the
ability for the demand side to provide flexibility to the market is relatively untapped. To
alter this, we have the following recommendations.
6.2.1
Green value
The phase out of regulated tariffs for some customer classes and the increased
development of non-regulated options provides an opportunity for retailers to increase
their ‘green power’ offers for renewable energy supplies. Such offers allow
consumers to display their willingness to pay for green energy. Where there is willingness
to pay, this will drive demand for and also the value of REGOs. This creates an incentive
for retailers to contract with renewable energy sources following the end of the FiT support
period, in order to secure REGOs and so be able to demonstrate the ‘greenness’ of their
supply. In so doing, this should also create value for renewable generators through trade
of REGOs alongside power output. The incentives for consumers to secure green power
supply deals can be enhanced by ensuring that they only pay once for the green energy
component – either the REGO value or the green component CSPE, but not both.
The development of green power offers could be stimulated by requiring public entities
tendering for power requirements to secure a specific proportion of green power to meet
their overall needs. This could help to kick-start green tariffs across a broader consumer
base.
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6.2.2
Smart metering and demand side management
Following a trial and cost-benefit analysis, CRE released a decision on 7 July 2011
recommended to the French Government the full roll-out of the electricity smart meter
‘Linky’. This was formally adopted by the Government in September 2011 and published
to the Official Journal on 10 February 2012. During 2013, ERDF issued its roll-out
calendar but it is unlikely that the EU Directive 2009/72/CE target where 80% of clients
are to be equipped before 2020 will be met46. Works to establish an appropriate
regulatory framework for ‘Linky’ are also being progressed by CRE.
The on-going ‘Linky’ smart meter rollout provides an opportunity to achieve increased
demand side involvement within the market and is linked to the greater development of
‘smart grids’ in France. To take advantage of potential smart meter functionality, this rollout needs to be coupled with dynamic, time of use tariffs in order to enable price
responsive behaviour from the demand side and mechanisms to allow aggregated
demand side resources to participate in the market in a meaningful manner. This could
bring new sources of flexibility to the intraday markets and help with the balancing of wind.
The ‘Linky’ rollout provides a route to deliver this outcome, if the opportunity is taken.
46
CRE, ‘Annual Report 2013’.
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7.
CARBON REGIME
Decarbonisation of the electricity sector is central to Europe’s plans to reduce carbon
emissions in an effort to tackle climate change. But a policy dilemma exists concerning
how to achieve this goal. Most stakeholders support a market-based approach in which a
strong CO2 pricing regime drives investment in low carbon generation. However,
Government-sponsored policies, such as direct financial support or organised
mechanisms for capacity procurement, are increasingly being used to deliver the
‘required’ mix of generation instead.
This Section focuses on the issues being experienced under the carbon regime to date
and options for enhancing it to better enable a carbon pricing system to deliver investment
in future.
7.1
Current situation
7.1.1
Context in Europe
Under an effective carbon regime, low carbon investment should be possible without
project-specific support. Investors considering a potential low carbon project backed by a
carbon price regime will need to form a view of the carbon price trajectory and the
resultant power price for the economic lifetime of the project. Critically, this view needs to
be bankable. Any deviation between outturn carbon (and therefore electricity) prices and
those anticipated at the point of investment results in the risk of financial exposure,
increasing project costs (risk premia) or delaying investment.
However, experience from the EU ETS during Phases II and III highlights, as shown in
Figure 10, that carbon prices have been insufficient to deliver investment in low carbon
generation. The current carbon regime is not a bankable proposition for low carbon
investment. As a result, there is increasing reliance across Europe as a whole on support
mechanisms to enable RES investment.
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Figure 10 – Spot carbon prices in the EU ETS
35
Dry period in Spain
Phase 1
Record oil (and therefore gas)
price increases
Rising oil prices & cold
winter
Phase 2
Phase 3
Phase 1 oversupply
revealed
25
Recession leads to oil
price decreases and
lower energy demand
Fukushima disaster
20
Eurozone debt
crisis
15
1st back-loading
vote rejected
10
Expectation of recovery
in demand and &
commodity prices
Phase 1
NAPs cut
5
Further Phase 1
oversupply revealed
Mar 2014
Nov 2013
Jul 2013
Mar 2013
Jul 2012
Nov 2012
Mar 2012
Nov 2011
Jul 2011
Mar 2011
Apr 2010
Dec 2009
Aug 2009
Apr 2009
Dec 2008
Apr 2008
Aug 2008
Dec 2007
Aug 2007
Apr 2007
Dec 2006
Apr 2006
Aug 2006
Dec 2005
Aug 2005
May 2005
Jan 2005
0
Dec 2010
Phase 3 auctioning begins and
back-loading uncertainty
Aug 2010
Spot carbon price (€/tCO2)
30
Source: Thomson Reuters
7.1.2
Issues faced
The need for investor certainty in this context has increased dependence upon support
mechanisms to deliver RES investment in France and across Europe in general. This has
an undermining influence on an already low carbon price because the level of investment
delivered via direct support is not reflected within the level of allowances available in the
EU ETS.
7.2
Recommended market design enhancements
The ultimate long-term goal is for an effective carbon regime that:
§
allows for investment in low carbon generation without the need for out-of-market
support; and
§
integrates low carbon generation fully into the market.
Such a regime internalises a more appropriate value of carbon within wholesale price
formation and provides greater certainty for low carbon investors that they capture this
value through their wholesale revenue streams. This reduces the need for renewable
support schemes, as the carbon externality value is better reflected within the wholesale
price directly. During the transition to such a regime, there may be differential impact
between low carbon technologies and, where in place, the vintage of renewables support
in place.
A carbon pricing solution is technology neutral, with the marginal carbon price, through its
influence on the wholesale price, forming an important element of remuneration for all low
carbon investors. It is not possible to price discriminate between different low carbon
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options and offer differentiated or banded support to individual technologies/projects
based on underlying costs. This technology neutrality provides incentives for delivery of
cheaper alternatives as it allows infra-marginal rent to be earned, which is positive for the
efficiency of the overall outcome.
However, during the transition to such a regime the ability for projects to capture this rent
will vary. Differences are outlined in a simplistic manner as follows:
§
existing renewables supported under the current vintage of fixed FiT do not have the
potential to capture any upside, as their revenue stream is set by the FiT;
§
future renewables projects supported under a variable premium, such as a 2-way CfD
FiT, have the potential to capture increased wholesale revenue, while support
payments will correspondingly reduce; and
§
future renewables projects supported under a fixed premium have the potential to
capture upside from increased wholesale revenue streams, while still receiving the
fixed premium.
§
Delivering an improved carbon regime with credibility to support investment decisions will
take time and broad commitment from policy makers and market participants. Therefore,
it is a long-term goal, but it should remain in the vision of policy makers today. In this
context, we have the following recommendations.
7.2.1
Credible framework
Certainty for investors (and the cost of capital) could be improved through enhanced
institutional credibility for the carbon regime. Ideally, this would be in the form of broad
international agreement (preferably global or, as a second best, European) with
associated treaties. To the extent that governments grow to rely on revenue from
allocations of CO2 (or its taxation) or alternatively the scale of the ‘green economy’, this
also enhances future credibility of a strong CO 2 pricing regime.
7.2.2
Flexibility mechanisms
Carbon markets are a political construct. As such, the carbon regime is entirely open to
future policy change. An independent carbon bank role could be created to reduce
political influence on the mechanics and operation of the carbon regime. Under this
approach, government sets the overall decarbonisation policy goals/targets for the future,
but the carbon bank has independence in respect of managing the carbon regime to
deliver the targets.
A carbon bank could also remove the problem of the long term credibility of the market by
offering contracts on the price of carbon - in essence a ‘put option’ on the price of
carbon, or some other form of project-specific compensation in the event that the CO 2
regime is weakened in the future.
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Additionally, pre-determined adjustment mechanisms, such as the proposed Market
Stability Reserve, can help to improve market functioning and so bolster long-term
credibility of the carbon regime. Such mechanisms should be promoted in order to deliver
this goal.
7.2.3
Carbon revenue recycling
A critical underlying factor behind a credible carbon pricing regime is acceptance from
energy customers that the costs of decarbonisation are acceptable and therefore that they
are willing to pay for it.
A carbon pricing solution is technology neutral with the marginal carbon price, through its
influence on the wholesale price, forming an important element of remuneration for all low
carbon investors. This technology neutrality provides incentives for delivery of cheaper
alternatives as it allows infra-marginal rent to be earned.
If there is a perception that infra-marginal rent (profit) is ‘too high’ (e.g. for existing wind or
nuclear), leading to issues of public acceptability one option is to recycle carbon auction
revenue back to electricity consumers (domestic and/or energy intensive users in open
industries). This option would maintain the surplus achieved by producers but provide a
reduction in costs to end users and so is likely to increase the acceptability of such profits.
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8.
RECOMMENDATIONS AND NEXT STEPS
There are clear drivers within France and across Europe more broadly for modifications to
electricity market design and RES support mechanisms. There are two intertwined
objectives: to integrate renewables within the market and to make the market fit for
purpose for a high RES future. The ultimate objective is to remove support mechanisms
for established RES.
To support these objectives, we have proposed a series of recommendations across
building blocks that span the value chain ranging from grid access, through wholesale
market arrangements to retail. Our recommendations are summarised in Table 4.
The main focus of the recommendations is as follows across the building blocks:
§ Grid access. Parties should have clear grid access rights and timely connections at
reasonable cost.
§ Wholesale market. Greater liquidity and adequate products should be available to
allow parties to manage commercial positions.
§ Imbalance arrangements. Imbalance arrangements should provide appropriate
incentives to balance, with tools available to manage imbalance risk.
§ RES support. Support should be market-based with appropriate design for market
integration.
§ Retail. Retail market should value green energy as well as provide demand-side
flexibility.
§ Carbon regime. In the long-term, well-designed carbon pricing should prevail over
RES support. However, this cannot be achieved without a credible and sustainable
carbon regime across the EU.
The recommendations provide practical options for enhancing the French electricity
market design. They would provide greater certainty in relation to grid access and
improved routes to market and trading options, while integrating RES within the market.
Critically, these proposals can provide a bridge to the ultimate objective of removing
support mechanisms for established RES.
The recommendations are presented as a package of complementary measures to be
progressed in tandem to support the integration of renewables into the market. They are
necessary complements to the policy objectives of balance responsibility and increased
wholesale market exposure for renewable generators. They enhance the market
arrangements to allow renewable generators to manage risks linked to market
participation. Without this package of recommendations, parties will have reduced ability
to manage market risk, which is likely to increase prices for consumers and frustrate
efficient market operation.
The recommendations are focused on arrangements for future projects. Arrangements for
existing projects should continue to operate as originally intended to avoid retrospective
change and the destabilising effect that this can have on future investors. Therefore, it is
vital that retrospective changes are not made, which would undermine confidence, and
that the existing FiT is grandfathered for projects developed under it. Revisions to the
future scheme should not alter the support afforded to projects being developed under the
existing FiT1.
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Table 4 – Summary of recommendations by building block
Block
Aim
Grid
access
§
Recommendations
Improving certainty,
transparency and
competition
§
§
§
§
Wholesale
market
§
Enhancing access to
market and
developing
appropriate products
§
§
§
§
Imbalance
§
Ensuring costreflective imbalance
prices
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§
§
Grid access should be provided on a
‘connect and manage’ basis and access
rights must be clearly defined and
honoured
The provision of connection works should
be subject to effective competition
Connection charges should be ‘shallow’ in
nature to cover the costs of local/nonshared works only
Network regulation can be enhanced to
better align the interests of the network
businesses with those of system users and
ensure timely development of
infrastructure. This includes extension of
regulatory oversight for distribution network
operators
Internal intraday auctions should be
developed, including cross border with
access to intraday capacity
Trading products should be available at
half-hourly granularity, with cross border
trading
Production forecast and outturn information
should be made available by technology at
transmission and distribution levels
A centralised marketplace for trading
REGOs could be established
Imbalance pricing should be a single price
structure, not dual
Gate closure for trade nominations should
be reduced from 1 hour
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Block
Aim
RES
support
§
Recommendations
Making support more
market-oriented while
limiting exposure to
risks that cannot be
managed
§
Future RES support arrangements in
France should be based on a variable
premium approach with a cost control
mechanism linked to overall end-user
prices
§
Support should be restricted for zero shortrun marginal cost generation in periods of
negative wholesale prices
§
The enduring allocation and price discovery
arrangements should be based on a
competitive auction or tender process,
when conditions for effective competition
are met.
As a transitional measure, allocation should
be determined through an administrative
process, with technology banding and
pricing that reflects pay-as-clear within
bands
Grandfathering of support to existing
projects
§
§
Retail
Carbon
regime
§
§
Stimulating value for
green power and
accessing demand
side potential
§
Allowing carbon to
take over from
dependence on RES
support in a
sustainable, credible
framework
§
§
§
§
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Encourage customers (especially public
entities) to secure a specific portion of
green power in their public tenders
Smart meter rollout needs to be coupled
with dynamic, time of use tariffs in order to
enable price responsive behaviour and
mechanisms to allow aggregated Demand
Side Response to participate in the market
Enhanced institutional credibility for the
carbon regime, ideally broad international
agreement, preferably global or EU
Pre-determined adjustment mechanisms,
such as the proposed Market Stability
Reserve, can help to improve market
functioning
Recycle carbon auction revenue back to
consumers (domestic and/or energy
intensive users in open industries)
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Table 5 highlights, for each of the market design building blocks where proposals were
made, potential consequences of not implementing the recommendations.
Table 5 – Consequences of not implementing recommendations
Block
Aim
Recommendations
Grid
access
§
Improving certainty,
transparency and
competition
Continued uncertainty for developers regarding
timing and costs of connection will slow project
delivery and increase costs
Wholesale
market
§
Enhancing access
to market and
developing
appropriate
products
Persistence of limited liquidity on the intraday
market and absence of half-hourly products (with
cross border trading) will restrict the ability for
generators to manage risks linked to balancing
responsibility
Imbalance
§
Ensuring costreflective
imbalance prices
Maintaining the dual price approach will continue
to undervalue imbalances in the opposite
direction to the system position, affecting
autonomous generation in particular
RES
support
§
Making support
more marketoriented while
limiting exposure to
risks that cannot be
managed
While the existing FiT can still persist if unaltered
in accordance with State Aid guidelines, this will
not facilitate the integration of RES within the
market. Adopting the proposed RES support,
once all the recommendations for integration of
RES into the electricity market have been made,
arrangements will allow RES to be progressed
within a workable balance of risk and reward
Retail
§
Stimulating value
for green power
and accessing
demand side
potential
Green energy will be undervalued and the ability
for the demand side to contribute to a more
efficient system will not be realised
Carbon
regime
§
Allowing carbon to
take over from
dependence on
RES support in a
sustainable,
credible framework
If the carbon regime is weak and the supporting
framework lacks enduring credibility, the external
costs linked to carbon will continue to have a
minor effect on wholesale price formation,
extending the period over which RES support is
needed
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QUALITY AND DOCUMENT CONTROL
Quality control
Report’s unique identifier: 2014/513
Role
Name
Date
Author(s):
Simon Bradbury
September 2014
Julien Cosse
Matthieu Mollard
Approved by:
Matt Brown
September 2014
Stephen Woodhouse
Franck Avedissian
QC review by:
September 2014
Document control
Version no.
Unique id.
Principal changes
Date
v1_0
2014/513
Draft client version
September 2014
V2_0
2014/513
Minor edits
September 2014
V3_0
2014/513
Minor edits
September 2014
V4_0
2014/513
Final client version
September 2014
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