Smarter Network Storage
Low Carbon Network Fund
Electricity storage in GB:
SNS4.13 – Interim Report on the Regulatory and Legal
Framework
Electricity storage in GB
Regulatory and legal framework
Contents
Executive Summary ............................................................................................................... 3
Headline messages ....................................................................................................... 3
Electricity markets are changing in pursuit of decarbonisation ..................................... 3
Business case for distribution connected storage can be complex .............................. 3
Regulatory framework presents issues for distribution connected storage .................. 4
1
Introduction.................................................................................................................... 8
1.1 Context .................................................................................................................... 8
1.2 Purpose of this report .............................................................................................. 8
1.3 Structure of this report ............................................................................................. 9
2
Impact of decarbonisation on GB electricity system ................................................... 10
2.1 The generation mix is evolving in response to policy goals .................................. 10
2.2 Implications of increased renewable generation ................................................... 10
2.3 Future need for energy storage to help provide flexibility ..................................... 12
2.4 Positive statements from policy makers regarding storage .................................. 13
3
Energy storage has many forms and applications ...................................................... 16
3.1 What is energy storage? ....................................................................................... 16
3.2 How can storage be used? ................................................................................... 17
3.3 What are the challenges for further development and deployment? .................... 20
4
Regulatory framework building blocks ........................................................................ 21
4.1 Building blocks of EU framework .......................................................................... 21
4.2 Building blocks of GB framework .......................................................................... 22
5
Regulatory arrangements: what are the implications for storage? ............................. 25
5.1 How is storage classified in the existing framework? ........................................... 25
5.2 How is ownership and operation of storage affected? .......................................... 30
5.3 How will storage investments be treated in price controls? .................................. 36
5.4 Summary of issues for storage within regulatory framework ................................ 36
5.5 Implications for SNS business models .................................................................. 38
6
Market participation and service provision: how can storage realise value? .............. 39
6.1 Possible avenues for value realisation .................................................................. 39
6.2 Wholesale market ................................................................................................. 40
6.3 Balancing services ................................................................................................ 45
6.4 Capacity market .................................................................................................... 47
6.5 Levy Exempt Certificates ...................................................................................... 49
6.6 Issues linked to value realisation .......................................................................... 50
7
Conclusions ................................................................................................................. 51
7.1 Key observations ................................................................................................... 51
7.2 Next steps ............................................................................................................. 52
Annex A – EU and GB Legal framework overview ......................................................... 53
Annex B – Generation requirements ............................................................................... 61
Annex C – Wholesale market ............................................................................................ 64
Annex D – Balancing Services ......................................................................................... 68
Annex E – Capacity market ............................................................................................... 69
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Electricity storage in GB
Regulatory and legal framework
Executive Summary
Headline messages
The GB electricity system is evolving in pursuit of decarbonisation, with significant penetrations of autonomous wind
and solar generation anticipated. Increased flexibility is needed to manage the unpredictability and variability of
intermittent generation and deliver system stability. In this context, electricity storage has a potentially important role to
play as a source of flexibility in the future capacity mix.
Electricity storage is a diverse concept, encompassing a broad range of technologies with varied potential applications.
This means that the business case for distribution connected storage is typically multi-layered, with several distinct
components in the value stream, typically involving multiple parties. The feasibility of the business case is influenced
by the regulatory framework. But, the legal and regulatory framework presents several issues for increased
deployment of electricity storage within the GB market. These issues need to be appropriately addressed if the
potential benefits of electricity storage to the system are to be realised.
Electricity markets are changing in pursuit of decarbonisation
The transition to a low carbon electricity sector will create challenges for the electricity system. A decarbonised
electricity system requires a radically different generation mix from that seen conventionally. It will include a
considerable quantity of capacity that is less flexible than the present fleet, whether due to technical inflexibility (such
as variable or intermittent renewable generation) or commercial inflexibility (due to low or zero marginal costs, perhaps
exacerbated by output-based support mechanisms). Meanwhile, the decarbonisation of the wider economy will require
electricity to be used for heating and transport, significantly increasing total electricity demand and changing patterns of
consumption. The Distribution Network Operator (DNO) will have an increased requirement to reinforce for peak load
unless peak load can be smoothed.
To manage these challenges, we will, in future, need to draw on flexibility from a wide range of sources to balance the
system and provide security of supply. Energy storage is one source of flexibility which could help to balance the
system and provide an alternative to traditional network reinforcement.
At present, however, aside from pumped storage hydro, there is limited storage in the GB electricity market. This is, in
part, linked to the underlying economics of storage options given limited deployment and traditional reliance on large
scale conventional generation assets to meet demand. But looking beyond these factors, there is a genuine question
regarding the ability of the existing regulatory and legal framework to support enhanced deployment and utilisation of
energy storage options. The Smarter Network Storage (SNS) project is seeking to shed light on this issue.
One of the aims of the SNS project is to review relevant aspects of the regulatory and legal arrangements for the GB
electricity sector, in order to identify possible barriers to the wider introduction of electricity storage facilities on DNO
networks. This report is the first element of this process. It initiates the review process by identifying the overarching
framework for storage and potential issues for further investigation.
Business case for distribution connected storage can be complex
Distribution connected storage is likely to have mixture of applications. One value stream component lies in avoided or
deferred capex linked to conventional system reinforcement options. Other sources of value stem from the ability of
the storage asset to provide ancillary services and to participate in the wholesale market. In addition, there are
potential wider societal benefits in the form reduced CO 2 emissions and avoided investment in other sources of
capacity to provide flexibility.
These possible value streams are, therefore, linked to a range of factors and typically require involvement from multiple
actors across the value chain to be realised. For example, the distribution business must be involved to capture
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Electricity storage in GB
Regulatory and legal framework
benefits of avoided capex while wholesale market revenues necessitate involvement of market players. The multicomponent and multi-actor nature of the business case is illustrated in Figure 1.
Figure 1 – Business case components for distribution connected storage
Avoided
conventional
capex
Value within
DNO business
Revenue
from
ancillary
services
Revenue
from
wholesale
market
Business
case
Value outside conventional
DNO business
1
The SNS project considers several business cases for distribution connected storage:





DNO merchant: DNO builds, owns and operates the asset. Full operational control.
DSO: DNO builds, owns and operates the asset. DNO has full operational control. DNO has been given a wider
role in regulation in balancing or controlling aggregated demand and generation on its network (a ‘DSO’ role).
DNO contracted: DNO builds, owns and operates the asset. DNO has full operational control. Prior to
construction, long term contracts (e.g. 10 years) for the commercial control of the asset outside of specified
windows are agreed.
Contracted services: DNO offers a long term contract (e.g. 10 years) for services at a specific location with
commercial control in certain periods
Charging incentives: DNO sets DUoS to create signals for peak shaving that reflect the value of reinforcement.
Regulatory framework presents issues for distribution connected storage
The feasibility of these business cases is influenced by the regulatory framework. However, there are several issues
within the legal and regulatory framework which affect the deployment and utilisation of distribution connected
electricity storage within the GB market. These result from a combination of EU-wide and GB-specific rules. The key
messages which arise from the regulatory review for deployment of storage assets on distribution networks, with the
involvement of the DNO are as follows:
Default treatment of storage as a subset of generation creates uncertainty
Unlike in the gas sector where storage is defined as a distinct activity, electricity storage is not explicitly recognised as
a discrete activity or asset class in the GB and EU legal frameworks. In the absence of an alternative option, storage is
treated as a type of generation asset. This is an accident of history through the liberalisation process rather than a
deliberate design choice. Nevertheless, treatment of storage as generation is a pervasive issue which has a ripple
effect on ownership and operation options.
1
Business models are outlined in full at: http://innovation.ukpowernetworks.co.uk/innovation/en/Projects/tier-2-projects/Smarter-NetworkStorage-(SNS)/Project-Documents/Smarter-Network-Storage-Business-model-consultation.pdf
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Electricity storage in GB
Regulatory and legal framework
Generation licence exemption route does allow distribution connected storage projects of
appropriate size in a manner consistent with unbundling requirements
As part of the liberalisation process, ‘unbundling’ has become enshrined in the regulatory frameworks at EU and GB
levels. This seeks to separate network and non-network activities, restricting the ability for operators of network assets
to be active in generation or supply sectors. For GB DNOs, the requirement is for legal, functional and accounting
unbundling to ensure operational independence of the distribution business from other activities within the vertically
integrated business. Therefore, in GB, distribution licence holders are prohibited from also holding generation or
supply licences.
This appears to block GB DNO involvement in storage ownership and operation. However, a class exemption exists
for ‘small generators’, meaning that storage projects with either output below 50MW are exempted from the need to
hold a generation licence, with individual exemptions typically offered to capacity below 100MW. This exemption is
applied on a per site basis. Therefore, smaller-scale, distribution connected storage facilities qualify for this exemption.
The exemption route does, consequently, provide an avenue for potential deployment of smaller scale energy storage
assets by DNOs, with operational separation to a third party to handle energy flows, in a manner that is consistent with
unbundling requirements.
This is the model being employed in the SNS demonstration, with interaction of the storage asset with the balancing
and wholesale markets being handled via third parties, independent from the DNO business.
De minimis business restrictions do place a loose limit on deployment by DNOs
Non-distribution business activities, such as income generation from storage projects, are limited by de minimis
restrictions specified in the distribution licence. These restrictions mean that turnover from and investment in nondistribution activities must not exceed 2.5% of DNO business revenue or licensee’s share capital respectively.
However, this limit is relatively loose at present, creating the potential for projects to be progressed within this
restriction.
But, possible application and operation of assets is affected though by the need to ensure that
competition in generation and supply is not distorted
More critically, though, the distribution licence imposes restrictions upon activities of the distribution business in order
to avoid distortion of competition in generation or supply activities. DNO operation of a storage asset would have an
impact on the traded market and it will be necessary to demonstrate that this does not distort the market. This can be
interpreted as a block on operation of a storage asset by a DNO for balancing purposes. It requires a contractual
interface with a third party to handle the energy flows which necessitates the involvement of an additional player in the
business case.
This is the model in place in the SNS demonstrations, with third parties managing the interactions with the balancing
and wholesale markets, and the trials will test arrangements for managing this third party interaction within the trading
arrangements.
Alternatively, it may be possible for GB DNOs to be allowed to trade for non-speculative purposes in order to deliver
network services under a model similar to that within which National Grid operates as system operator.
Treatment of storage investments in price controls is unclear
The treatment of investment in a storage asset as an alternative to conventional investment options, its assessment
and treatment within the price control process has not been tested.
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Electricity storage in GB
Regulatory and legal framework
Summary position
DNO-led development of smaller scale storage projects is, therefore, possible within the regulatory framework.
However, the need to ensure that distribution licence holders do not distort competition in generation and supply blocks
the ability for operation of the assets by DNOs. This creates the need for a contractual interface with a third party
(potentially an operationally separate entity under the same organisation umbrella as the DNO business) to conduct
market interactions (as is the case in the SNS demonstrations).
The importance of the issues identified for DNO led development of distribution connected storage assets is
summarised in a qualitative assessment summarised in Figure 2.
Figure 2 – Summary qualitative assessment of regulatory issues
Default treatment of storage as generation
Avoiding distortion of competition in generation and supply
Unbundling requirements
De minimis business restrictions
Assessment of economic benefits under price control
High
Medium
Low
These regulatory issues have differing implications for the five business models discussed within the context of the
SNS project. In general, these issues are of greater significance for the business models which entail DNO ownership
and operation of the storage asset. This stems principally from the concern that DNO activity in storage projects could
distort competition in generation and supply activities. A qualitative assessment of the implications of these issues for
the business models is shown in Figure 3. Regulatory issues are less of an issue for the Charging Incentives model
(and to a lesser extent the Contracted Services model). However, these models present more commercial risk for
DNOs and provide less certainty regarding the actual progression of investment, potentially creating system security
issues. These factors must be balanced against the reduced presence of regulatory issues under these models.
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Electricity storage in GB
Regulatory and legal framework
Figure 3 – Importance of regulatory issues for SNS business models
Issue
DNO merchant
DSO
DNO contracted
Contracted
services
Charging
incentives
2
2
1
0
0
4
4
2
2
0
2
2
1
0
0
1
1
1
0
0
4
4
4
2
0
Default treatment
as generation
Distortion of
competition
Unbundling
requirements
De minimis
restrictions
Assessment of
economic benefits
Key: Low importance
01234
High importance
There is scope for the regulatory regime to be modified to create a more appropriate framework within which
distribution connected storage can be progressed by addressing the issues identified above. The next phase of this
element of the SNS project will move onto consider potential solutions to improve the regulatory framework.
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Electricity storage in GB
Regulatory and legal framework
1 Introduction
1.1 Context
The generation mix is evolving in response to policy goals to pursue decarbonisation of the power sector and to
increase the proportion of electricity generated from renewable sources. The proportion of generation provided by
wind and solar capacity is increasing as a result and this trend is expected to continue going forward.
Wind and solar generation are ‘autonomous’ in nature and have limited commercial sensitivity to the system needs (in
response to market prices). As a result, greater flexibility will be needed to manage the unpredictability and variability
of intermittent generation. Electricity storage is one possible source of flexibility. However, deployment of storage is
limited at present, with large scale pumped storage hydro schemes the main source.
In addition to developments in generation, the evolution of ‘smart’ technologies has the potential to change patterns of
consumption and to open up new options for grid management. Electricity storage has a role to play here too, helping
to manage potentially more variable patterns of usage and the implications for the grid.
The Smarter Network Storage (SNS) project is focused upon demonstrating the potential benefits of employing storage
solution on a distribution network in place of conventional network reinforcement. The business case for this is linked
to the economic value of the avoided network reinforcement costs and the ability for storage to capture revenue from
providing ancillary services and/or bulk energy trading. This, in turn, is driven by the regulatory and market
arrangements and their implications for storage deployment.
The SNS project explores several possible business models for distribution connected storage. These models are
presented in Table 1 and are referred to later in this document. Two models in particular are being tested through the
SNS demonstration; ‘DNO contracted’ and ‘Contracted services’.
1.2 Purpose of this report
This report focuses on the regulatory and market arrangements which affect the deployment and utilisation of electricity
storage on distribution networks within the GB market. The aim is to highlight issues within the arrangements which
could frustrate greater deployment of storage.
This report does not consider regulatory issues concerning planning, consents and business rating. Such issues are
being considered in a separate document related to planning.
This represents the first step in the process. The next step is to consider how the arrangements could be modified to
address the issues identified. The aim is to create an appropriate framework which enables deployment of projects
such as that being demonstrated in SNS project as part of an effective and economic electricity market in GB, as we
pursue decarbonisation.
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Electricity storage in GB
Regulatory and legal framework
Table 1 – SNS business models
Business model
DNO merchant
Key points
Full merchant risk, exposed to
power price and balancing
services
Distribution
System
Operator (DSO)
DNO exposed to incentive
scheme
DNO contracted
DNO exposed to construction
and operational risks
Contracted
services
Low commercial risk for DNO
Charging
incentives
No guarantee of asset being
build
Description

DNO builds, owns and operates the asset. Full operational
control.

DNO monetises additional value streams directly on a short
term basis (e.g. trading).

Possible barriers: Costs of accessing the market, DNO skills
and capabilities, regulation and shareholder expectations of
risk.

DNO builds, owns and operates the asset. DNO has full
operational control.

DNO has DSO role; coordinating portfolios of flexibility for
both distribution and wider system benefit through a
centralized control mechanism.

DNO commercial risk is dependent on design of incentive
scheme.

DNO builds, owns and operates the asset. DNO has full
operational control.

Prior to construction, long term contracts (e.g. 10 years) for
the commercial control of the asset outside of specified
windows are agreed.

Dependant on the feasibility of long term contracts.

DNO offers a long term contract (e.g. 10 years) for services
at a specific location with commercial control in certain
periods.

Third party responsible for building owning, and operating
the asset and monetising additional revenue streams.

DNO sets DUoS to create signals for peak shaving that
reflect the value of reinforcement.

Barriers: no operational control for DNO, therefore no
guarantee on security.
1.3 Structure of this report
The report is structured as follows:






Section 2 provides context focusing on the evolution of electricity markets in pursuit of decarbonisation, the
potential for storage and factors which influence its treatment;
Section 3 outlines the diversity of electricity storage technologies and their diversity;
Section 4 sets out important building blocks which form the basis of the regulatory and legal framework that affects
electricity storage;
Section 5 outlines issues which relate to the treatment of storage within the regulatory framework and the
consequential implications;
Section 6 considers issues relating to market participation and service provision by storage; and
Section 7 summarises key messages and outlines next steps.
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Regulatory and legal framework
2 Impact of decarbonisation on GB electricity system
Many stakeholders within the electricity sector are calling for increased deployment of storage on the system. This
section outlines the drivers behind this and highlights the emphasis being placed upon storage within the policy
framework debate.
2.1 The generation mix is evolving in response to policy goals
Power sector decarbonisation is a clear component of energy policy. This necessitates a dramatic transformation of
Europe’s electricity markets and renewable electricity has a particularly important role to play within the revised
capacity mix. European markets are, therefore, expected to face an unprecedented rate of expansion of renewable
generation in the future. Indeed in many countries, these targets have already fundamentally changed the generation
mix, with much greater reliance on wind and solar generation. This coincides with the closure of thermal plants through
the EU Large Combustion Plant Directive (LCPD) and the Industrial Emissions Directive (IED).
2.2 Implications of increased renewable generation
A significant proportion of renewable generation developed to date is wind and solar capacity. Future renewable
capacity development is expected to continue this trend. Wind and solar generation are ‘autonomous’ in nature and
have limited commercial sensitivity to the system needs (in response to market prices). In addition, as low-carbon
support payments are delivery-based (i.e. per MWh of low-carbon output), this new low-carbon generation is less
reliant than other generation on the rewards for delivery that can be obtained from trading with market participants.
Pöyry has carried out a number of detailed quantitative studies exploring the impact of the intermittency on European
electricity and gas markets. We draw on these studies to illustrate this issue.
Figure 4 shows the impact for GB of the demand duration curves when we subtract the output of the wind from the total
2
demand . These charts illustrate the proportion of a year that system demand is above a given level: the upper line
shows the character of the gross system, and the lower line is the remainder when the intermittent generation is
subtracted. It is the lower line that the other power stations on the system will have to supply.
Figure 4 – Demand duration curves for GB and Ireland in 2030
British market
Irish market
8
75
Demand
Demand
Demand net wind
Demand net wind
65
6
55
4
GW
GW
45
35
25
2
0
100%
80%
60%
40%
20%
0%
15
-2
5
100%
-5
80%
60%
40%
20%
0%
-4
Installed capacity and demand from Core scenario.
2
‘Impact of Intermittency. How wind variability could change The shape of the British and Irish electricity markets. Summary report’, July
2009, Pöyry Management Consulting.
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Electricity storage in GB
Regulatory and legal framework
Figure 5 and Figure 6 illustrate how the generation and wholesale price patterns in Northern Europe could look in 2030
3
for two snapshot periods which apply two different historic weather patterns to a potential future generation mix
involving greater penetration of wind and solar capacity:


Figure 5 is for a still period in the winter (i.e. relatively low wind output). Christmas 2006 was marked by a high
pressure area across much of Europe. In GB, wind generation is very low for the period from 17 December to 28
December, but since this period coincides with low demand over Christmas, the effect on prices is dampened.
Prices plunge on 28 December following a sharp pick-up in wind output.
Figure 6 is for a windy period in the winter. A particularly windy period occurred on 11 January, when it was windy
across many European countries together. In Germany, generation is sustained above 60GW throughout the day.
The generally high level of wind generation has a clear effect on prices which remain low for a long period. The
fall in wind output between 21 and 26 January is accompanied by a rise in prices.
Figure 5 – Still period across N Europe. 15-31 Dec 2030 (weather of 2006)
(GW)
CCGT
Coal
CHP
Onshore wind
Nuclear
Offshore wind
Intercon. and p. storage
3
‘Northern European Wind and Solar Intermittency Study. The impact of wind and solar generation on the electricity markets of Northern
Europe. A multi-client study’. Pöyry Management Consulting, January 2011.
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Regulatory and legal framework
Figure 6 – Windy period across N Europe. 10-26 Jan 2030 (weather of 2009)
(GW)
Onshore wind
Offshore wind
Intercon. and pumped storage
(2009 €/MWh)
2.3 Future need for energy storage to help provide flexibility
As a result, greater flexibility will be needed to manage the unpredictability and variability of intermittent generation
(wind and solar). This could be provided by four sources: flexible generation, interconnection, demand side response
and electricity storage. These four options and their ability to provide flexibility are illustrated in Figure 7.
Whether and how the flexibility offered by these sources will be provided depends on the market and regulatory
structure available to incentivise new capacity to enter the market, including storage. With this in mind, is important to
note that there are positive statements from policy makers regarding the application of storage which creates an
enabling environment for developing an appropriate market and regulatory framework to enable this to come to fruition.
The position of policy makers is elaborated in the next section.
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Regulatory and legal framework
Figure 7 – Sources of flexibility
Flexible
Generation
Increased
interconnection
Demand
Side
Response
Electricity
Storage
Peaking capacity for low
wind periods
Interconnection to
neighbouring markets
Incentives for peak demand
reduction
Energy export for low wind
periods
Incentives for peak price
avoidance / reduction
Flexible plants to deal with
short-term variability
Full utilisation of network to
reduce wind curtailment
Heat electrification with
flexibility potential
Flexible charging patterns
from electric vehicles
Flexible generation at
renewables sites
Transmission reinforcement
to link wind to demand
Demand reduction for
balancing services
Energy import for high wind
periods
Storage at point of
generation – small or large
Full utilisation of network to
reduce wind curtailment
Storage of electrified heat
Storage linked to electric
vehicles
Provision of national or local
for balancing services
2.4 Positive statements from policy makers regarding storage
As understanding of the challenges presented by the drive towards decarbonisation, so has the desire to integrate
renewables into the system more effectively and to ensure that flexibility is provided from other sources. Energy
storage is often cited by policymakers as an important part of the solution.
2.4.1
What does the European Commission say?
2.4.1.1
Future role of energy storage
4
DG Energy outlines its views regarding the importance of energy storage in its January 2013 Working Paper : In this it
provides the following opinion:
‘Energy storage will play a key role in enabling the EU to develop a low-carbon electricity system. Energy storage can
supply more flexibility and balancing to the grid, providing a back-up to intermittent renewable energy. Locally, it can
improve the management of distribution networks, reducing costs and improving efficiency. In this way, it can ease the
market introduction of renewables, accelerate the decarbonisation of the electricity grid, improve the security and
efficiency of electricity transmission and distribution (reduce unplanned loop flows, grid congestion, voltage and
frequency variations), stabilise market prices for electricity, while also ensuring a higher security of energy supply.’
Furthermore, it states that the challenges of the future ‘calls for a new approach to storage as a key component of the
future low-carbon electricity system.’ This echoes the message within the Commission’s Energy Roadmap 2050 which
highlights the following as one of 10 conditions required to deliver a decarbonised energy system:
4
‘DG ENER Working Paper: The future role and challenges of Energy Storage’ DG Energy, January 2013.
http://ec.europa.eu/energy/infrastructure/doc/energy-storage/2013/energy_storage.pdf
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Regulatory and legal framework
‘A new sense of urgency and collective responsibility must be brought to bear on the development of new energy
infrastructure and storage capacities across Europe and with neighbours’.
Delivering energy infrastructure including storage Trans-European energy infrastructure
To support delivery of its objectives for an integrated energy market and to enable the EU to meet its broader climate
and energy goals, the EC has identified strategic energy infrastructure priorities, including energy storage projects.
Through Regulation 347/2013 on guidelines for trans-European energy infrastructure, the EC’s aim is to make sure that
strategic energy networks and storage facilities are completed by 2020. The Regulation identifies key energy
infrastructure projects termed ‘Projects of Common Interest’ (PCIs) located in priority energy corridors.
For a project to be included in the list, it has to have significant benefits for at least two Member States; contribute to
market integration and further competition; enhance security of supply, and reduce CO 2 emissions. PCIs stand to
benefit from a streamlined permitting process, improved regulatory treatment and may have access to EU funding
through the Connecting Europe Facility (CEF) to support their development.
Electricity storage facilities which fit the following definition are classed as eligible energy infrastructure categories:

‘electricity storage facilities used for storing electricity on a permanent or temporary basis in above-ground or
underground infrastructure or geological sites, provided they are directly connected to high-voltage transmission
lines designed for a voltage of 110 kV or more’.
Such a facility can be classed as a PCI if it fulfils the following requirement:

‘the project provides at least 225 MW installed capacity and has a storage capacity that allows a net annual
electricity generation of 250 Gigawatt-hours/year.’
Therefore, larger scale storage projects connected to high voltage transmission lines can be classed as PCIs.
However, smaller scale, distribution connected storage projects are not supported through the PCI framework.
5
248 PCIs have been identified across the electricity, gas oil and carbon capture and storage networks , 14 of which
relate to electricity storage (with two smart grid projects). The EC states that these projects will contribute to the better
integration of the internal electricity market, enhance the preparedness of the grid to take up increasing amounts of
6
energy from variable renewable sources and maintain system stability at the same time . There is, however, scope for
a similar type of framework to be developed for smaller scale, distribution connected storage projects.
2.4.2
What does the UK government say?
DECC acknowledges the potential role of storage as a source of flexibility that can help to match supply and demand in
a system with increasing levels of intermittent generation. In its 2012 document ‘Electricity System: Assessment of
7
Future Challenges’ , DECC highlights the potential role for storage as follows:
‘Storage has the technical ability to provide a number of benefits to the electricity system – for example, by smoothing
supply profiles from variable generation and potentially reducing constraint costs by allowing generation to run during
periods of low demand. It can also potentially save or defer network upgrade costs that may be required in the future
to meet peak demand.’
5
6
7
http://ec.europa.eu/energy/infrastructure/pci/pci_en.htm
COM(2013) 711 ‘Long term infrastructure vision for Europe and beyond’.
https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/48549/6098-electricity-system-assessment-future-chall.pdf
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8
DECC’s 2012 Energy Security Strategy emphasises this further, stating that ‘to remain balanced, our system will need
sufficient reliable capacity to meet demand as well as a variety of non-generation technologies, including storage,
interconnection and demand side response’.
In recognition of the challenges facing the system as decarbonisation progresses, DECC and Ofgem established the
Smart Grid Forum to focus on how electricity network companies can respond to become more flexible and integrated
for the future. This includes consideration of the potential application of storage within smart grids.
Also, to support the ability for non-generation balancing technologies, including electricity storage, to contribute to the
responsiveness challenges, DECC is seeking to ensure that Electricity Market Reform is implemented in a way that
allows the development of flexible solutions to generation challenges. We consider this further later in the document.
8
https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/65643/7101-energy-security-strategy.pdf
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3 Energy storage has many forms and applications
There is a rationale and political support for increased storage deployment, as outlined in the previous section. In this
context, this section explores what is meant by storage and its potential applications.
3.1 What is energy storage?
Energy storage is not a homogenous concept. The term ‘energy storage’ encompasses a wide range of technologies
with diverse capabilities. To illustrate the diversity, Figure 8 displays the power rating and discharge duration of a
selection of storage technologies. Available storage options span these two dimensions, ranging from low power rating
and short discharge duration options such as super-capacitors through to pumped storage hydro which combines high
power rating and long discharge duration. Therefore, referring to ‘energy storage’ is a generality which risks
oversimplifying the diversity of energy storage and its potential applications. It also raises the question of whether
there should be different classes of energy storage technologies, with the potential for differing treatment for each
within the regulatory frameworks.
Figure 8 – Range of storage technologies and capabilities
Metal-Air Batteries
Pumped Hydro
SodiumSulphur Battery Advanced Lead Acid Battery
Compressed Air Energy
ZEBRA Battery
Storage
High Energy
Super Caps
Minutes
Lithium-Ion Battery
Lead Acid Battery
Nickel-Cadmium Battery
Nickel-Metal Hydride Battery
Seconds
Discharge duration
Hours
Flow Batteries
High Power Fly Wheels
Superconducting
Magnetic Energy
Storage
High Power Super Caps
1kW
10kW
100kW
1MW
10MW
100MW
1GW
Power rating
Source: THINK report
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3.2 How can storage be used?
The technical diversity on offer across the range of energy storage technologies means that, collectively, they can be
deployed for a wide range of applications, with each technology suited to a different space within this range. Figure 9
shows the range of services to which energy storage can be applied. The nature of potential service provision spans a
range of applications including:

uninterruptible power supply: the provision of services to end-users to provide security and quality of electricity
supplies;
grid support: the provision of services to distribution and transmission network operators to deliver system stability,
manage peak load, voltage/thermal contracting management and provide balancing services; and
energy management: bulk energy trading.


The ability for individual storage technologies to participate in these activities is linked to their technical characteristics.
Figure 9 illustrates the relationship between the range of potential applications and technical characteristics in terms of
power rating and discharge duration. Options with high power ratings and longer discharge durations are well suited to
providing energy management services and balancing services to TSOs. Those technologies with lower power ratings
and shorter discharge durations are better suited to provision of services to DNOs and end-users.
Figure 9 – Range of applications
Uninterruptable
Power Supply
Energy
Management
Grid Support
Hours
Bulk energy
trading
Arbitrage
Secondary reserve
Blackstart
Minutes
Discharge duration
Primary reserve
Frequency control
Voltage support
Transmission stability
Seconds
Voltage support
Load levelling/following
Load factor increase
Capacity deferral
Peak shaving
Power quality
Uninterruptible power supplies
1kW
10kW
100kW
1MW
10MW
100MW
1GW
Power rating
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Source: Adapted from THINK report
Overlaying Figure 8 and Figure 9 provides a mapping between different storage options and their suitability for
providing uninterruptible power supply, grid support and energy management, based on underlying technical
characteristics. The output from this mapping is shown in Figure 10. It highlights, for example, that pumped hydro and
compressed air energy storage are well suited to provision of energy management, while batteries are suited to grid
support and/or end-consumer applications depending upon the particular technology.
Figure 10 – Mapping storage technologies to range of services
Uninterruptable
Power Supply
Energy
Management
Grid Support
Metal-Air Batteries
Pumped Hydro
SodiumSulphur Battery Advanced Lead Acid Battery
Compressed Air Energy
ZEBRA Battery
Storage
High Energy
Super Caps
Minutes
Lithium-Ion Battery
Lead Acid Battery
Nickel-Cadmium Battery
Nickel-Metal Hydride Battery
Seconds
Discharge duration
Hours
Flow Batteries
High Power Fly Wheels
Superconducting
Magnetic Energy
Storage
High Power Super Caps
1kW
10kW
100kW
1MW
10MW
100MW
1GW
Power rating
Source: THINK report
This also serves to highlight that different technologies are dependent upon different and often multiple sources for
their revenue. The sources of revenue include regulated sources, coming from contracts regulated businesses or
directly from regulatory arrangements, and from non-regulated or market arrangements. This is illustrated in Figure 11,
which provides a simplistic overview of how the nature of applications to which storage can be used influences its
revenue sources. This highlights that where storage is applied to the provision of ancillary services or capex deferral,
revenue streams are heavily driven by regulation. However, if storage is being used for energy management
purposes, a greater proportion of its income can be derived from market sources.
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Figure 11 – Sources of revenue
Grid Support
Energy
Management
Reduced reliance
on income from
regulated
businesses
Reliance on income from
services to regulated businesses
Reduced reliance
on income from
regulated
businesses
Minutes
Seconds
Discharge duration
Hours
Uninterruptable
Power Supply
Income from regulated sources
Income from non-regulated sources
1kW
10kW
100kW
1MW
10MW
100MW
1GW
Power rating
Source: Adapted from THINK report
The nature of underlying sources of revenue affects the business case for storage:



if the storage technology is likely to be predominantly used to provide services to regulated businesses, then the
regulatory framework and processes for acquiring such services needs to allow storage to capture appropriate
value to make it feasible;
if the project is expected to focus on activities within competitive markets, then it needs to be able to access the
market on an equal footing with other participants; or
where revenue sources are split, the balance and relative priorities between regulated and non-regulated services
must be structured in an appropriate manner to allow both the business case to hold and the required services to
be delivered.
The diverse capabilities of different energy storage options mean, therefore, that there is scope for much variation in
the way in which different technologies are utilised and, as a consequence, in their sources of revenue. This means
that the underlying business models for different applications of storage options vary, as do the regulatory and market
arrangements required to support them. DG Energy concurs with this view, stating that ‘in a future low-carbon energy
system, storage will be needed at all points of the electricity system’ and also noting that business models, regulatory
changes and incentives need to be developed to cover the range of relevant applications and stakeholders.
One representation of the current status of different technologies in terms of maturity and range of associated power
costs is highlighted in Figure 12. This shows that the majority of storage technologies are in research and
development, early commercialisation or demonstration phases. There is also a broad range of costs associated with
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installing storage capacity at present, which in most cases exceeds the cost of an open-cycle gas-turbine (~€500600/kW), which provides an alternative source of flexibility. Costs are expected to reduce as the technologies develop
and deployment increases. But achieving greater deployment relies upon a valid business case for projects both now
and in the longer-term.
Figure 12 – Storage technology power costs and maturity
Source: Adapted from THINK report
3.3 What are the challenges for further development and deployment?
Given the requirements for flexibility as the system decarbonises and the positive statements from policy makers
regarding the deployment of storage, why is storage not more prevalent? DG Energy identifies the following
challenges:




technological, such as capacity and efficiency of existing technologies;
economics; driven by technology costs;
strategic, requiring a holistic approach for the development of storage given its ability to complement other
features of the system; and
market and regulation, relating to incentives for developing storage assets and the business case.
Each issue is a valid consideration. Our focus in this report relates to the final category. The following sections
explore the issues and potential barriers for storage in GB specifically relating to the legal and regulatory frameworks
which have a potential impact on business models for storage.
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4 Regulatory framework building blocks
The regulatory framework that applies to the GB electricity sector is formed by a combination of EU and GB rules. The
EU arrangements provide an overarching umbrella, which must be reflected in national arrangements. In addition to
reflecting the EU arrangements, the GB framework also details the specific arrangements to apply at a national level.
The sections below summarise the frameworks in place and a number of the key components within them. Further
details are provided in Annex A.
4.1 Building blocks of EU framework
4.1.1
Architecture
EU legislation consists of several layers, ranging from high level commitments to specific and directly applicable
legislative acts, while it also includes non-binding legislative instruments. Figure 13 shows the hierarchical layers of
EU legislation, from the high level objectives set out in the treaties to the specific regulations and decisions and the
non-binding recommendations and opinions.
Figure 13 – Hierarchical layers of EU frameworks
The EU legal framework is outlined in more detail in Annex A, but there are some important components that it is worth
drawing out here.
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4.1.2
Key building blocks
rd
The ‘Electricity Directive’ 2009/72/EC (also referred to as the ‘3 Energy Package’) is particularly relevant in the
rd
context of this project. The 3 Energy Package is the most recent of a sequence of Directives focused on promoting
liberalisation, competition and an effective internal energy market across EU. One of the central tenets of this process
is ensuring separation between vertically integrated entities that are active across both network related and market
activities. The extent and nature of separation required varies depending upon the particular network activity. There is
a distinction between transmission system operation and transmission asset ownership, for example. Similarly, there is
a differentiation between transmission and distribution activities. This has a particular bearing upon ownership and
operation of storage assets. This is discussed further in Section 5.2.
The EU regulatory framework is also the source of one of the drivers behind a potential increase in the role for storage.
In an effort to tackle climate change, the EU has an aspiration to reduce greenhouse gas emissions to 80-95% below
9
1990 levels by 2050 . Decarbonisation of the electricity sector is central to Europe’s plans to reduce carbon emissions,
10
and EURELECTRIC has a commitment to achieve carbon neutral electricity by 2050 .
Achieving decarbonisation goals requires a dramatic transformation of Europe’s electricity markets, switching from
conventional fossil fuels to low carbon generation sources. The current framework for delivering these changes spans
both European and national legislation. To date, this has been driven by the EU 2020 climate change package which
set the following objectives for 2020:



a 20% reduction in EU greenhouse gas emissions from 1990 levels;
raising the share of EU energy consumption produced from renewable resources to 20%; and
a 20% improvement in the EU's energy efficiency.
11
In January 2014, the European Commission built on this by outlining its draft 2030 climate change framework . This
includes the following targets for 2030:


a 40% reduction in EU greenhouse gas emissions from 1990 levels; and
raising the share of EU energy consumption produced from renewable resources to 27%.
The EU 2020 climate change package, in combination with national support schemes, is a key factor behind the
investment in renewable technologies including wind and solar. This is a driver for increased storage deployment, as
discussed previously in Section 2.
9
European Council Conclusions 29/30 October 2009. Paragraph 7: “The European Council calls upon all Parties to embrace the 2°C objective
and to agree to global emission reductions of at least 50%, and aggregate developed country emission reductions of at least 80-95%, as part
of such global emission reductions, by 2050 compared to 1990 levels; such objectives should provide both the aspiration and the yardstick to
establish mid-term goals, subject to regular scientific review. It supports an EU objective, in the context of necessary reductions according to
the IPCC by developed countries as a group, to reduce emissions by 80-95% by 2050 compared to 1990 levels.”
10
Recognising the responsibility of the power sector as a major emitter of greenhouse gas, sixty one Chief Executives of electricity companies
representing well over 70% of total EU power generation signed a Declaration in March 2009, committing to action to achieve carbonneutrality by mid-century. The EURELECTRIC ‘Power Choices’ study builds on this commitment and seeks to examine how this vision can
be made a reality.
11
Communication: A policy framework for climate and energy in the period from 2020 to 2030. European Commission, January 2014
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4.2 Building blocks of GB framework
4.2.1
Architecture
In the UK, primary legislation comes in the form of Acts of Parliament and statutory instruments constitute the majority
of delegated (secondary) legislation. Statutory instruments are made in a variety of forms, most commonly Orders in
Council, regulations, rules and orders. The form to be adopted is usually set out in the enabling Act.
Statutory instruments (SIs) are a form of legislation which allows the provisions of an Act of Parliament to be
subsequently brought into force or altered without Parliament having to pass a new Act. Acts of Parliament confer
powers on Ministers to make more detailed orders, rules or regulations by means of statutory instruments. An Act will
often contain a broad framework and statutory instruments are used to provide the necessary detail that would be too
complex to include in the Act itself. Statutory instruments can also be used to amend, update or enforce existing
primary legislation.
Beneath legislation, there are licences which outline rules and responsibilities relating to specific activities within the
sector. Generation, transmission, distribution and supply activities are all prohibited without the relevant licence,
unless either a class or an individual exemption applies. An interconnector licence has latterly been added to the preexisting suite. Electricity storage is not a licensable activity. The next layer of the framework is made up of industry
codes and agreements, which focus on arrangements for participation within the sector.
Figure 14 – Hierarchical layers of GB frameworks
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4.2.2
Key building blocks
The Electricity Act 1989 (as amended) is the main legislative component of the GB legal framework. It was the
legislative vehicle that delivered liberalisation of the electricity sector and it remains at the heart of the GB electricity
market framework today. It recognises generation, transmission, distribution and supply as distinct activities and,
places a legal prohibition upon carrying out these activities without a licence (unless otherwise exempted). It is also
rd
the vehicle for ensuring that unbundling requirements within the 3 Energy Package are embodied within the GB
system.
The ambition for decarbonisation is also embedded within UK policy. Through the 2008 Climate Change Act, the UK
established the world’s first legally binding climate change target, stated as an aim to reduce the UK’s greenhouse gas
emissions by at least 80% (from the 1990 baseline) by 2050. Also, as part of the EU target for a 20% contribution of
renewable energy by 2020, the UK has a national target for 15% renewable energy.
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5 Regulatory arrangements: what are the implications for storage?
The current regulatory arrangements for the electricity sector affect treatment of electricity storage within the market
and the potential deployment of storage assets by industry participants. This section considers the implications of the
regulatory arrangements for storage, identifying issues that the current framework presents. The areas focused upon
are as follows:


the classification of storage; and
implications of the arrangements for ownership and operation of storage.
5.1 How is storage classified in the existing framework?
5.1.1
The liberalisation process defined distinct electricity sector activities
The market liberalisation process, which began in the 1990s in GB, split the electricity supply chain into several distinct
layers; generation, transmission, distribution and supply. This split separated natural monopoly, network activities
(transmission and distribution) from areas where competition could develop (generation and supply), with the goal of
enhancing efficiency across the sector as a whole. The medium for delivering efficiency improvements differs across
the different layers of the supply chain, with direct regulation applied in the case of network activities and reliance on
market forces in the competitive sectors. This structure remains in place today in GB and has become the common
model across much of Europe, with clear delineation between the vertical layers of the industry.
The current regulatory framework is a product of this process. The Electricity Act 1989 (as amended) was the
legislative vehicle that delivered liberalisation of the electricity sector and it remains at the heart of the GB electricity
12
market framework today . It recognises generation, transmission, distribution and supply as distinct activities and,
through section 4(1), places a legal prohibition upon carrying out these activities without a licence (unless otherwise
exempted). The activities allowed by these licences and relevant associated definitions are provided in Table 2.
12
The Electricity Act 1989 has been amended and supplemented by various provisions of the Utilities Act 2000, the Energy Acts of 2004, 2008,
2010 and 2011.
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Table 2 – GB framework electricity sector activity definitions
Activities
Generation
Definition

Licence allows the licensee to generate electricity for the purpose of giving a
supply to any premises or enabling a supply to be given

‘Generate’ means generate at a relevant place
Transmission


Distribution


Supply


Licence allows the licensee to participate in the transmission of electricity for
the purpose of enabling a supply to be given
‘Transmission’ means transmission by means of a transmission system,
where a transmission system is a system which consists (wholly or mainly) of
high voltage lines and electrical plant and is used for conveying electricity
from a generating station to a substation, from one generating station to
another or from one substation to another
Licence allows the licensee to distribute electricity for the purpose of enabling
a supply to be given
‘Distribute’ means distribute by means of a distribution system, that is to say,
a system which consists (wholly or mainly) of low voltage lines and electrical
plant and is used for conveying electricity to any premises or to any other
distribution system
Licence allows the licensee to supply electricity to premises in cases where—
(a) it is conveyed to the premises wholly or partly by means of a distribution
system, or
(b) (without being so conveyed) it is supplied to the premises from a
substation to which it has been conveyed by means of a transmission
system,
but does not include its supply to premises occupied by a licence holder for
the purpose of carrying on activities which he is authorised by his licence to
carry on.
This split between electricity sector activities has also been enshrined within the European legislation in pursuit of a
13
liberalised, single European energy market. This began with the establishment of Directive 96/92/EC , subsequently
referred to as the ‘first energy package’ and has been supplemented since, with ‘third energy package’, embodied
14
within Directive 2009/72/EC , the latest development to the framework in this regard. This defines the principal
electricity sector activities as outlined in Table 3.
13
‘Directive 96/92/EC of the European Parliament and of the Council of 19 December 1996 concerning common rules for the internal market in
electricity’ http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:31996L0092:EN:HTML
14
‘Directive 2009/72/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in
electricity and repealing Directive 2003/54/EC’. http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2009:211:0055:0093:EN:PDF
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Table 3 – EU framework electricity sector activity definitions
Activities
Generation
Definition

‘Generation’ means the production of electricity
Transmission

‘Transmission’ means the transport of electricity on the extra high-voltage
and high-voltage interconnected system with a view to its delivery to final
customers or to distributors, but does not include supply
Distribution

‘Distribution’ means the transport of electricity on high-voltage, mediumvoltage and low-voltage distribution systems with a view to its delivery to
customers, but does not include supply
Supply

‘Supply’ means the sale, including resale, of electricity to customers
5.1.2
Energy storage is not a defined activity within the electricity sector
The pursuit of liberalisation within the sector means that the electricity frameworks in both GB and EU define the
conventional electricity sector activities of generation, transmission, distribution and supply. However, energy storage
is not explicitly recognised as a discrete activity or asset class (although within the gas market, gas storage is a distinct
licensed activity).
In the absence of an alternative option, energy storage has been treated as a type of generation asset. In GB, large
scale pumped storage hydro assets such as the facilities at Ffestiniog and Dinorwig hold generation licences, while
15
smaller scale facilities can qualify for exemption from the requirement to hold a generation licence .
This default treatment of storage as a type of generation is an accident of history rather than a deliberate design
choice. As the large scale pumped storage facilities can compete with generation in the provision of bulk energy or
balancing services, it was simply convenient to include the pumped storage assets within the generation category,
rather than progress an alternative solution. While larger scale assets which deliver energy on a comparable basis to
conventional generation can operate under the ‘generation’ banner, it is more problematic for smaller scale resources
that have different applications.
But what is really meant by ‘generation’ and is the inclusion of storage as a subset of generation appropriate? From a
European context, ‘generation’ is defined as the production of electricity (as outlined in Table 3), while the definition in
the Electricity Act 1989 simply links the activity to generating electricity for the purpose of giving or enabling supply of
electricity to a premises (as outlined in Table 2)., Both are relatively generic definitions. The Electricity (Class
Exemptions from the Requirement for a Licence) Order 2001 develops the definition of ‘generation’ further, as
highlighted in Table 4.
15
Exemptions from the requirement to hold a generation licence can be granted to classes of generators or to particular generators in specific
circumstances specified in ‘The Electricity (Class Exemptions from the Requirement for a Licence) Order 2001’. A generator can be
exemptible as a small generator if output to the total system (GB transmission system and all distribution systems) is less than 10MW, or if
output to the total system is less than 50MW and the declared net capacity of the power station is less than 100MW. The definition of
‘declared net capacity’ in this context is as follows: ‘The declared net capacity of a generating station which is driven by any means other
than water, wind or solar power is the highest generation of electricity (at the main alternator terminals) which can be maintained indefinitely
without causing damage to the plant less so much of that capacity as is consumed by the plant’.
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Table 4 – GB generation definitions and applicability for storage
Source
Electricity Act
1989, 4(1)(a)
Definition

Licence allows the licensee to
generate electricity for the purpose of
giving a supply to any premises or
enabling a supply to be given
Comments

What if storage is intended to
provide network related
services (at least primarily)
and is not intended to directly
supply or enable supply to
premises?
Order,
Interpretations
paragraph 2(d)

A person shall be treated as
generating electricity at any time if he
is the operator of plant or equipment
which at that time—
(i) is generating or capable of
generating electricity; or
(ii) is not capable of generating
electricity only by reason of the
maintenance, repair or testing of the
plant or equipment.



Does storage actually
generate electricity?
It could be argued that
electricity storage technologies
without a turbine (such as the
SNS project) do not actually
generate electricity, but rather
import electricity for
subsequent export.
Pumped storage hydro may be
considered to generate
electricity as it produces
electricity by flowing water
from reservoirs through
turbines.
Order,
Schedule 2,
Class A

Persons (other than licensed
generators) who do not at any time
provide more electrical power from
any one generating station than—
(1) 10 megawatts; or
(2) 50 megawatts in the case of a
generating station with a declared net
capacity of less than 100 megawatts.

This links exemption for small
generators to ‘declared net
capacity’ (which is considered
in the row below)
Order,
Schedule 1
The definition of ‘declared net capacity’
includes the following:

The declared net capacity of a
generating station which is driven by
any means other than water, wind or
solar power is the highest generation
of electricity (at the main alternator
terminals) which can be maintained
indefinitely without causing damage
to the plant less so much of that
capacity as is consumed by the plant.

Declared net capacity is linked
to production at ‘the main
alternator terminals’.
An alternator converts
mechanical energy into
electrical energy. But, an
alternator is not necessarily a
feature of electricity storage
technologies.
As this does not work for
batteries, the definition needs
to be revised to reflect the
equivalent interface on a
battery storage system


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When considering whether storage can be treated as generation, a case can be made either way. On one hand, it is
possible to argue that storage technologies that do not involve a turbine (such as the SNS project) does not actually
generate electricity, rather it stores electricity for subsequent release. On the other hand, it is possible to say that at
times storage is capable of generating or at least acting like a generator.
This highlights two important messages in relation to the GB framework:


first, that the definition of generation is unclear; and
second, that storage does not sit comfortably within the definition of generation as its stands.
In the context of smaller-scale, distribution connected storage projects, the generation licence exemption conditions
become important. Points to note are that exemption is granted:


on a plant by plant basis (not across a portfolio); and
to plants with output below 10MW or below 50MW if net declared capacity is below 100MW.
This allows small scale electricity storage facilities to fall under the ‘Small Generator’ class exemption, thereby
obviating the requirement to hold a generation licence for such facilities. These thresholds are more than sufficient for
most distribution constraint avoidance applications, for which assets of sub-10MW are required.
While storage does share some features with generation, it is also different in many regards e.g. demand consumption
which is greater than output potential due to round-trip efficiency. Interconnection and demand side participation also
share some features with generation, but they are not subject to the generation licence regime. Indeed, the Electricity
Act 1989 has been amended to make interconnector operation a licensable activity, making it a discrete activity with its
own licence (as discussed further below), while demand side response is not a licensable activity. The treatment of
storage within the regulatory arrangements should be given specific consideration, rather than persisting with default
treatment as a type of generation.
Revised treatment of interconnectors
Although not explicitly recognised as a distinct activity in the early stages of liberalisation,
interconnection has latterly been defined within the legislative framework. The EU Electricity
Directive defines an electricity interconnector as ‘equipment used to link electricity systems’
and, in GB, the Electricity Act 1989 has been amended to define interconnection as a
licensable activity (Section 4(1)(d)).
The inclusion of interconnection as a defined activity is linked to its role in delivering the internal
market with effective cross-border trades. Regulation 714/2009 states the following:
‘The precondition for effective competition in the internal market in electricity is nondiscriminatory and transparent charges for network use including interconnecting lines in the
transmission system. The available capacity of those lines should be set at the maximum levels
consistent with the safety standards of secure network operation.’
Licensing provided a route for allowing non-discriminatory access to and cost reflective
charging for interconnectors. It is their importance for delivering efficient cross-border flows
and hence delivery of an effective internal market that triggered the change in regulatory
approach for interconnection.
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5.1.3
Summary: energy storage is not explicitly reflected in the regulatory framework
Neither the GB nor the EU regulatory frameworks for electricity explicitly recognise energy storage as an asset class or
activity. In the absence of an alternative, the default position is that energy storage is treated as a subset of
generation. However, the definition of ‘generation’ is unclear and the inclusion of storage within its scope is
questionable.
This suggests that storage should be explicitly acknowledged within the regulatory framework, with its treatment linked
to the underlying application of the technology (i.e. network use, wholesale market interaction, ancillary service
provision or a mixture). Storage could be a separate licensed activity, which would provide clarity within a specifically
developed set of arrangements. Alternatively, it could simply be made clear that storage is not a subset of generation,
with storage potentially an unlicensed activity such as demand side participation.
As things stand, however, the default treatment of storage as generation has implications for ownership and operation
of energy storage assets. Treatment of storage as generation is a pervasive issue which has a ripple effect on
ownership and operation options, as discussed below.
5.2 How is ownership and operation of storage affected?
5.2.1
Unbundling requirements have implications for ownership and operation options
The liberalisation process not only distinguished between vertical segments of the electricity sector, but it also created,
over time, restrictions on ownership or operation of activities between the different levels. This particularly restricts the
ability for operators of network assets to be active in generation or supply sectors. The separation between network
and non-network activities is referred to as ‘unbundling’ and it is enshrined in the regulatory frameworks at EU and GB
levels.
At an EU level, the ‘third energy package’ sets out the requirements for unbundling. The purpose of unbundling is
clearly set out in paragraph 9 of the introductory text, which reads:
‘Without effective separation of networks from activities of generation and supply (effective unbundling), there is an
inherent risk of discrimination not only in the operation of the network but also in the incentives for vertically integrated
undertakings to invest adequately in their networks.’
With this valid goal specified, the ‘third energy package’ outlines the unbundling requirements which apply for
distribution system operators (DSOs) and transmission system operators (TSOs). The requirements are more onerous
for TSOs, who have a choice between three models:



ownership unbundling: which requires full ownership separation to ensure full independence of network
ownership from supply and generation interests;
independent system operator (ISO); which requires that an independent TSO with no interests in generation or
supply operates the system, while allowing ownership of the transmission network to remain within a vertically
integrated undertaking; and
independent transmission operator (ITO): which allows asset ownership and operation to remain within a
vertically integrated undertaking, but ITO has full operational independence from the rest of the business with
stringent rules on ring-fencing.
Ownership unbundling and ISO models require distinct ownership separation between an entity engaged in TSO
activities and any market related activities. This blocks TSOs from owning generation and, by extension, storage. The
ITO model does allow for common ownership, but requires full independence and ring-fencing from an operational
perspective.
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For DNOs, the requirement is not for ownership unbundling, but rather for legal unbundling, functional and accounting
unbundling to ensure operational independence of the distribution business from other activities within the vertically
16
integrated business . Exemptions are possible for DNOs serving less than 100,000 connected customers. The key
elements of the unbundling requirements are:

legal unbundling of the DNO from other activities of the vertically integrated undertaking not related to
distribution;
functional unbundling of the DNO in order to ensure its independence from other activities of the vertically
integrated undertaking, including management separation, effective decision making rights and a compliance
regime; and
accounting unbundling creating a requirement to keep separate accounts for DSO activities.


The GB system endorses the EU model. Section 7(2A) the Electricity Act 1989 (as amended) outlines that the
transmission licence conditions may prevent the holder from carrying out another activity that requires a licence. This
is backed up by Standard Condition B6 which prevents a transmission licence holder from conducting any business or
carrying on any activity other than the transmission business, which blocks the ability for the TSO to engage in
generation or supply activities for which licence exemptions are available.
For distribution, section 6(2) the Electricity Act 1989 (as amended) prevents an entity that holds a distribution licence
from holding either a supply licence or a generation licence. The Distribution Licence furthers this. Standard Condition
42 and 43 within Chapter 11 (Independence of the Distribution Business) of the licence require managerial and
operational systems that prevent other licensed entities from accessing confidential information, supported by a
compliance regime to ensure that separation is maintained. DECC has stated that these conditions address the
rd
17
unbundling requirements specified in the 3 Package .
The business models being tested in SNS comply with unbundling requirements by having third parties in place to
manage the interaction of the storage asset with the market. This delivers separation between the DNO business and
operation of the asset within the market.
Table 5 – GB and EU unbundling measures
Source
Electricity Act 1989,
6(2)
Definition

The same person may not be the holder of
both a distribution licence and
a) a generation licence; or
b) a supply licence
Comments

Licence exempt generation possible,
providing avenue for smaller storage
Third Energy
Package
2009/72/EC, Article
26, 1


16
17
Where the distribution system operator is part
of a vertically integrated undertaking, it shall
be independent at least in terms of its legal
form, organisation and decision making from
other activities not relating to distribution.
Those rules shall not create an obligation to
separate the ownership of assets of the
distribution system operator from the vertically
integrated undertaking.
Legal rather than full ownership
unbundling. Does require operational
separation of storage from distribution
business
Article 26 of the Electricity Directive.
‘Implementation of the EU Third Internal Energy Package – Government Response’, DECC, January 2010.
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5.2.2
DNO ownership of generation licence exempt storage is possible under unbundling, with
operational separation
The unbundling requirements mean that, as a general rule, TSOs and DNOs must be independent from generation and
supply activities. As energy storage is classified as a subset of generation by default, this means that TSOs and DNOs
are unable to own and operate storage assets that require a generation licence. This acts as a block for the
deployment of large storage facilities by network operators as an alternative to conventional reinforcement or for
network management purposes.
However, as highlighted above, it is possible for exemptions from the requirement to hold a generation licence to be
18
granted. Four defined class exemptions exist, of which one is relevant here. This allows projects to be exemptible as
a ‘small generator’:


if output to the total system (GB transmission system and all distribution systems) is less than 10MW; or
if output to the total system is less than 50MW and the declared net capacity of the power station is less than
100MW.
It is important to note that the ‘small generator’ class exemption applies on a per generating station basis. This means
that exemption is possible for multiple projects that fall under the defined size thresholds, regardless of the cumulative
scale of the projects when considered collectively and the potential impact that they could have on the market in
aggregate.
Additionally, power stations which do not fall into any of the exemption classes listed above may apply to DECC to
seek an individual exemption. Power stations capable of exporting between 50MW and 100MW to the total system
19
that connected after 30 September 2000 are generally granted exemption via this route .
Some instances of network ownership and operation of storage do exist
In Italy, Art 36, paragraph 4, decree law 93/11 allows the TSO (and DSOs) to build and operate batteries.
However, this must be justified through a cost/benefit analysis that shows that the energy storage system
is the most efficient way to solve the problem identified (e.g. compared to the build of new line).
Remuneration from the storage asset should not be higher than the (measurable) cost of alternative
solutions.
Terna, the Italian TSO is currently working on six pilot projects with a rated capacity of 6MW and 40MWh,
and two of 15MW. In addition to these pilot plants, the company’s Terna Plus subsidiary, which is
responsible for new business development in Italy and abroad, is looking to commercialise energy
storage alongside other emerging technologies such as renewables and smart grid systems.
Belgian law allows some level of control by TSO/DSOs on electricity storage facilities but subject to
conditions that would ensure the functioning of an open, fair and transparent market. These conditions
are set out in Article 9 (1) of the Belgian Electricity Act:






18
19
the electricity is generated for balancing purposes only, with an explicit prohibition for commercial
purposes;
the stored electricity is called upon as a last resource;
under the form of negotiated drawing rights;
to the limit of the power needed for ancillary services;
upon the prior approval of the regulator; and
after having completed all relevant procedures for calling upon the market.
Class exemptions are specified in ‘The Electricity (Class Exemptions from the Requirement for a Licence) Order 2001’.
https://www.gov.uk/government/collections/electricity-licence-exemptions
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The exemption route does, therefore, provide an avenue for potential deployment of smaller scale energy storage
assets by DNOs, with operational separation.
The business models being tested in SNS deliver operational separation by having third parties in place to manage the
interaction of the storage asset with the market.
5.2.3
Deployment by DNO businesses is limited by de minimis restrictions
However, the possibility for income generation from smaller scale storage by DNOs must be considered in the context
of restrictions upon the activities of DNOs specified in the distribution licence.
20
Standard Condition 29 places limitations on non-distribution activities. It restricts:


total turnover from non-distribution activities to 2.5% of the DNO’s distribution business revenue; and
total investments in all non-distribution activities to 2.5% of the licensee’s share capital in issue, its share premium
and its consolidated reserves.
Therefore, there is a cap on the permitted revenue from and the overall level of investment in storage assets (as part of
a de minimis business), if such activities are possible. However, the limit is relatively loose and estimates suggest that
up to 15 projects equivalent to SNS could be deployed on some distribution networks before either of the thresholds
are close to being reached (subject to the scale of other activities which may already feed into the de minimis pot).
While the limit appears loose currently, arrangements for distribution network led storage projects need attention now
to avoid this becoming an undue restriction.
5.2.4
Obligation not to distort competition in supply and generation of affects arrangements for
and practicality of storage operation
More significantly, however, the Distribution Licence imposes restrictions upon activities of the distribution business to
avoid distortion of competition in generation or supply activities and to avoid cross-subsidy, as outlined in Table 6.
Operation of a storage device must be considered in this context. There are two ways in which flows into and out of
storage can be handled:


unmetered flows; or
trade to buy/sell power linked to charging/discharging of storage asset.
Whilst the net position is not material due to high round-trip efficiency, instantaneous charges and discharges are far
larger than the footprint of other network equipment (such as substation heating and lighting and technical losses in
cables and transformers) and larger than individual unmetered (i.e. estimated) connections such as streetlighting. If a
DNO were to adopt either approach, it would need to demonstrate that it was not acting in a way which could distort the
market.
In the first case, the effects of import and export flows are borne by other parties through effects on losses in a nonrd
transparent manner. This contradicts the 3 Energy Package which states that:
‘Each distribution system operator shall procure the energy it uses to cover energy losses and reserve capacity in its
system according to transparent, non-discriminatory and market based procedures, whenever it has such a function’
(Article 25.3).
Therefore, unmetered flows into and out of the storage facility may be problematic. This requires metering by the DNO
or by a third party, which must be accounted for within the settlement processes, supported by trading activity to
manage imports and exports.
20
Standard Condition 29: Restriction of activity and financial ring-fencing of the Distribution Business.
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This takes us to the second case. If the DNO undertakes trading activity to support the operation of the storage asset it
clearly involves direct DNO participation in the market, potentially affecting wholesale market activity. Trading does not
necessarily require either a generation or a supply licence. As already discussed, generation licence exemption is
available for storage assets of the size being considered here anyway. Also, trading to charge or discharge the
storage asset does not mean that the operator is seeking:


to ‘supply electricity to premises’, which is how supply activity is defined in the Electricity Act 1989 (see Table 2); or
to participate in ‘the sale, including resale, of electricity to customers’, which is how supply activity is defined in the
rd
3 Energy Package (see Table 3).
Therefore, trading to charge/discharge the storage asset does not appear to require a supply licence. Nevertheless,
trading by a DNO is likely to have an impact on generation and supply competition, which creates a potential distortion.
This effectively blocks operation of a storage asset by a DNO for balancing purposes.
These factors point to the need, under today’s regulatory framework, for a contractual interface with a third party to
handle the energy flows when the storage facility is used for network purposes or for broader system-wide offerings.
Therefore, an additional player must feature in the business case, potentially increasing its complexity.
This third party could potentially be a separate entity under the same organisation umbrella as the DNO business, as
long as the distribution business itself is appropriately ringfenced from such activities to comply with unbundling
requirements and associated licence restrictions. This includes the need to manage the potential for cross-subsidy
between different activities within the ‘Independence of the Distribution Business’ compliance regime.
The SNS business models being tested manage this issue by having contractual arrangements with third parties.
Under the ‘DNO contracted’ model, while the DNO owns the asset, the energy flows linked to its operation are handled
by a third party under contractual arrangements. To allow the DNO to capture benefits of deferred conventional capex,
this suggests that there needs to be a monetary flow from the third party to the DNO for use of the storage assets as
part of the long-term contract arrangements. Under the ‘Contracted services’ route, ownership and operation are both
in third party hands and so independent from the DNO. Here, the DNO does not face any capex and the monetary flow
is more likely to be from the DNO to the third party for provision of ancillary services.
The trials will test different arrangements for the managing this third party contractual interface within the trading
arrangements.
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Table 6 – Distribution licence conditions
Source
Standard Condition
4.1
Definition

The licensee must at all times manage and
operate the Distribution Business in a way that
is calculated to ensure that it does not restrict,
prevent, or distort competition in the supply of
electricity or gas, the shipping of gas, the
generation of electricity, or participation in the
operation of an Interconnector
Comments

This is generally interpreted as a
block on DNO trading. Trading to
charge / discharge storage for
network security purposes does not
imply trade for commercial benefit.
Nevertheless, trading in the wholesale
market does involve interactions with
generation and supply activities. This
can be managed by having a third
party undertaking trading activity.
Distribution
Licence, Condition
4.9


The licensee must ensure in carrying on its
activities that the Distribution Business does
not give any cross-subsidy to, or receive any
cross-subsidy from, any other business of:
(a) the licensee; or
(b) any Affiliate or Related Undertaking of the
licensee.
If the storage asset is operated by a
separate entity within the same
organisation umbrella as the DNO
business, then costs and revenues
need to be allocated on an
appropriate basis between the
relevant businesses to avoid crosssubsidy.
National Grid, as TSO, is, however, able to trade electricity for balancing purposes. It has a licence obligation to
21
operate the system in an ‘efficient, economic and co-ordinated manner’ . To achieve this, National Grid is able to
purchase balancing services, including the ability to trade electricity for balancing reasons. Trading for other purposes
22
23
is prohibited , including speculative trading . However, ownership and operation of storage assets by the TSO is not
possible given unbundling provisions and the risk that to do so would distort competition in generation and/or supply.
There is scope for considering whether this model can be applied to DNOs to allow trading that enables charging and
discharging of storage assets for network services, with appropriate restrictions to prevent speculative trading. Indeed,
rd
the 3 Energy Package contains provisions which apply for DSOs to taking on a balancing role:
‘Where a distribution system operator is responsible for balancing the distribution system, rules adopted by it for that
purpose shall be objective, transparent and non-discriminatory, including rules for the charging of system users of their
networks for energy imbalance’ (Article 25.6).
21
22
23
Standard Condition C16: Procurement and use of balancing services.
Standard Condition C2: Prohibited activities.
As specified in the Procurement Guidelines.
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5.3 How will storage investments be treated in price controls?
5.3.1
Assessment of storage investment in price control needs clarification
If we assume that DNOs are able to own storage for network purposes, its treatment within the price control process
needs consideration. If a DNO opts for a conventional asset replacement or reinforcement approach, it will be
assessed in comparison to expected efficient costs for that type of asset and a determined efficient cost level will feed
into the base revenue and the regulatory asset value. However, the treatment of investment in a storage asset as an
alternative to conventional investment options is unclear. If DNOs were to deploy a storage device today under one of
the licence exemptions, it would likely be overspending against its Capital allowance; but receiving income under the
de minimis restrictions. Both the capital expenditure and the income are visible to Ofgem through the regulatory
account, but perhaps not in a clear enough manner to allow benchmarking against other similar projects once several
DNOs were deploying storage.
Relevant issues for consideration include:


the availability of appropriate comparator cost data for storage deployment upon which to make an assessment,
which is complicated by the number of storage options, the range of associated costs and their maturity; and
how the assessment methodology will consider wider benefits of storage beyond those delivered to the DNO in
order to reach a decision as to whether or not the investment is efficient and justified.
To allow investment in storage to be feasible, an appropriate assessment methodology within the RIIO price control
24
framework is needed. In the RIIO handbook , Ofgem indicates that the case made in business plans ‘may also be
strengthened where they have considered other potential delivery solutions, including operational solutions such as
demand side management and alternative asset-based solutions’. The reference to ‘alternative asset-based solutions’
could include storage. But this needs confirmation as does the methodology for assessing storage investments.
5.4 Summary of issues for storage within regulatory framework
The combination of unbundling requirements and licence restrictions in the interests of promoting competition in
generation and supply places limits on the potential for network businesses to own and operate storage assets. The
restrictions are especially stringent for TSOs. There may be scope for DNOs to own small scale assets which are
exemptible from generation licence requirements, within the limits of the de-minimis restrictions. But operation of the
assets in terms of wholesale market participation must be conducted via a licenced third party (which could potentially
be another legally separate entity in the same umbrella organisation as the distribution business), given restrictions on
trading activity by DNOs. Finally, to invest in storage assets as an alternative to conventional network assets, the
regulatory assessment of efficient costs needs to handle storage appropriately.
There are several issues within the legal and regulatory framework which affect the deployment and utilisation of
storage within the GB market. These result from a combination of EU-wide and GB-specific rules. The key messages
which arise from the regulatory review for deployment of storage assets on distribution networks, with the involvement
of the DNO are as follows:
1.
2.
3.
4.
24
Default treatment of storage as a subset of generation creates uncertainty and raises potential issues.
But generation licence exemption route does provide flexibility to progress distribution connected storage projects
of appropriate size in a manner consistent with unbundling requirements.
De minimis business restrictions do place a limit loose limit on deployment by DNOs, if storage continues to be
classed as generation.
But, possible application and operation of assets is affected though by the need to ensure that competition in
generation and supply is not distorted.
http://www.ofgem.gov.uk/Networks/rpix20/ConsultDocs/Documents1/RIIO%20handbook.pdf
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DNO-led development of smaller scale storage projects is, therefore, possible within the regulatory framework.
However, the need to ensure that distribution licence holders do not distort competition in generation and supply blocks
the ability for operation of the assets by DNOs, necessitating the involvement of a third party to manage energy flows
linked to the asset. The importance of the issues identified for DNO led development of distribution connected storage
assets is summarised in Table 7.
Table 7 – Summary of issues linked to legislation and licensing
Issue
Default treatment
as generation
Implication

Neither the GB nor the EU regulatory
frameworks for electricity explicitly
recognise energy storage as an asset
class or activity. In the absence of an
alternative, the default position is that
energy storage is treated as a subset of
generation. However, the definition of
‘generation’ is unclear and the inclusion
of storage within its scope is
questionable.
Importance

High. Storage could be a separate
licensed activity, which would provide
clarity within a specifically developed set of
arrangements. Alternatively, it could
simply be made clear that storage is not a
subset of generation, with storage
potentially an unlicensed activity like
demand side participation.
Treatment of storage as generation is a
pervasive issue which has a ripple effect
on ownership and operation.
Avoiding
distortion of
competition in
generation and
supply

Unmetered operation and DNO
management of energy flows could both
distort competition

High. May prevent DNO from
buying/selling electricity to
charge/discharge storage. This creates
requirement for third party contracts to
manage energy flows which complicates
the business case.
Unbundling
requirements

DSOs are unable to own and operate
storage assets that require a generation
licence
This blocks deployment of storage
facilities by network operators as an
alternative to conventional
reinforcement or for network
management
De minimis restrictions place a cap on
the permitted revenue from and the
overall level of investment in storage
assets

Medium. The generation licence
exemption route does provide an avenue
for potential deployment of smaller scale
energy storage assets by DNOs, with
operational separation. Requires third
party involvement.

Low. The limit is relatively loose and
estimates suggest that up to 15 projects
equivalent to SNS could be deployed on
some distribution networks
Unclear if assessment during price
control process allows other benefits of
storage used by DNO to be recognised
in assessing economic merit when
determining if investment
justified/efficient

Medium. RIIO-ED1 framework could
expand assessment scope to capture all
benefits/revenue streams (of appropriate
projects given other regulatory
requirements) to show positive overall
economic case

De-minimis
restrictions

Assessment of
economic
benefits under
price control

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5.5 Implications for SNS business models
These regulatory issues have differing implications for the five business models discussed within the context of the
SNS project. In general, these issues are of greater significance for the business models which entail DNO ownership
and operation of the storage asset. This stems principally from the concern that DNO activity in storage projects could
distort competition in generation and supply activities. A qualitative assessment of the implications of these issues for
the business models is shown in Table 8. The importance of the issues themselves is not weighted, but the traffic light
colour coding from Table 7 is shown to give an indication of weightings.
For DNO Merchant and DSO business models, the role of the distribution business in the operation of the storage
assets is a major factor. For these models, the requirements to avoid distortion of competition and to adhere to
operational unbundling requirements are key issues. These issues have less importance in DNO Contracted and
Contracted Services business models, as the distribution business takes a progressively reduced role in asset
operation in these models. These issues could be addressed by providing distribution businesses with the ability to
trade for balancing purposes (and so operate the storage asset in this context), in a manner similar to National Grid,
with associated restrictions on speculative trading.
For the Charging Incentives model, the identified issues are not important factors as storage ownership and operation
rd
fall to a 3 party, meaning that the tensions with unbundling and distribution licence requirements are not applicable.
However, while regulatory issues are obviated, other challenges are apparent in this model. Notably, the DNO has
reduced certainty that investment will actually proceed, which has important implications for system security. In
rd
addition, the challenge of making the business case work falls to the 3 party, which may not appropriately incorporate
the benefit of the investment to the distribution business. Both factors mean that, while regulatory issues may be
lessened, the Charging Incentives model (and to a lesser extent the Contracted Services model) entail greater
commercial and system security risks.
Table 8 – Importance of regulatory issues for SNS business models
Issue
DNO merchant
DSO
DNO contracted
Contracted
services
Charging
incentives
2
2
1
0
0
4
4
2
2
0
2
2
1
0
0
1
1
1
0
0
4
4
4
2
0
Default treatment
as generation
Distortion of
competition
Unbundling
requirements
De minimis
restrictions
Assessment of
economic benefits
Key: Low importance
01234
High importance
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6 Market participation and service provision: how can storage realise value?
The characteristics of electricity storage means that it can be utilised for a variety of applications, as outlined in Section
3. Multiple uses means multiple sources of potential value, which creates a multi-layered business case. Making a
business case work across these layers can be complex.
6.1 Possible avenues for value realisation
To re-cap on the messages from Section 3, electricity storage has a broad span of potential applications across the
sector. The range of applications and, therefore, sources of potential value are summarised in Figure 15. In addition,
storage can provide wider benefits to the system such as the displacement of carbon emitting generation and/or high
operating cost plants.
Figure 15 – Range of possible applications across the value chain
Generation
Reduce
imbalances as part
of a portfolio
Generate revenues
through arbitrage
Displace higher
carbon generation
capacity
Network
Optimise network
reinforcement
Contribute to
quality of supply
targets
Ancillary services
Contribute to
ancillary services
requirements
Reduce the need
for additional
capacity
Supply
Wholesale hedging
requirements
Some value stems from market activities, such as participation within the wholesale market or provision of ancillary
services to the transmission system operator. An additional possible revenue stream is being created through the
introduction of a capacity market in GB. Other sources of value are linked to benefits from avoided network capex and
displaced generation capacity. The stack of possible sources of value is illustrated in Figure 16.
In reality, these sources of value can be difficult to access. A market-led project may expect to capture market-based
value but benefits of avoided network capex are more difficult to realise. A DNO-led investment can more easily
capture the avoided network capex benefit but faces barriers to realisation of market-oriented value.
The ability for distribution connected storage to realise value via these routes is considered in the following subsections.
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Figure 16 – Costs and benefits of an example storage facility
6.2 Wholesale market
6.2.1
Overview of wholesale market
The wholesale market, or the British Electricity Trading and Transmission Arrangements (BETTA), is illustrated in
Figure 17 and can be summarised by the following elements:




forwards and futures markets, that allow contracts for electricity to be struck up to several years ahead;
short-term ‘spot’ power exchanges, enabling participants to ‘fine-tune’ their contracts up until Gate Closure
(currently one hour before delivery);
a Balancing Mechanism (BM), which opens at Gate Closure, in which National Grid as System Operator (SO)
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.
Further details are provided in Annex C, with the sections below pulling out a number of important elements.
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Figure 17 – Great Britain electricity trading arrangements under BETTA
Sources: Ofgem and Pöyry Management Consulting.
6.2.2
Options for participation in wholesale market
In principle parties seeking to trade wholesale power have various route-to-market options. These range from a pure
merchant approach where various products are sold spot via their in-house trading desk, to long-term all-inclusive
bilateral offtake agreements where an offtaker takes volume risk and defines at the outset of the contract pricing rules
(including price-risk mitigation measures) for all products bundled together. Along this spectrum, there are numerous
combinations entailing a higher (or lower) market commitment, hence a higher (or lower) risk for the generator and
potentially higher (or lower) realisable value:



Traditional Power Purchase Agreements (PPAs) with, typically, licensed electricity suppliers, are the most
common approach for independent producers. They may take various forms and predominantly differ for the
structure of the electricity pricing terms, e.g. fixed prices, floored and/or indexed. In each case the counterparty
will expect to take a share of the total value to compensate it for transaction costs it incurs, any risks it is taking on
under the contract and to provide a margin.
Trading services approach involves outsourcing trading activities to an external entity that is active in the market
and will interface with the market on behalf of the generator. This is the model envisaged under the SNS
‘Contracted services’ business model.
Trading on own account is predominantly used by larger players, including utilities, that can benefit from
economies of scale and in-house trading expertise. The generator may incur additional balancing, trading and risk
management costs under this strategy, but is generally able to retain a higher value. This is the model envisaged
under the SNS ‘DNO merchant’ and ‘DSO’ business models.
This range is graphically summarised in Figure 18.
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Figure 18 – Spectrum of potential routes to market
The trade-off between these options balances the overheads of direct market participation (e.g. trading functions,
accession to industry codes, posting credit cover, etc.) versus the discount to the power price associated with
outsourcing trading. If a DNO owns the storage asset, it will not be able to trade it directly given the block on DNO
trading in today’s regulatory arrangements mentioned previously, leaving either of the other two routes available. If the
storage asset is owned by a market participant then all routes are open, with the choice linked to the circumstances of
the individual.
6.2.3
Factors affecting inclusion in trading arrangements
6.2.3.1
Trading Parties
Under any route-to-market, the energy linked to a storage asset must feed into the settlement processes. Settlement
arrangements are specified in the Balancing and Settlement Code (BSC) and any entity who wishes to physically trade
power must be a Trading Party and hold energy accounts to manage their physical and contractual positions.
Distribution licence holders are parties to the BSC. However, they are not Trading Parties and do not hold energy
accounts. The BSC does not itself block distribution businesses from market participation. This stems, instead, from
the licence requirement to avoid distortion of competition in generation and supply, as discussed in Section 5.
6.2.3.2
Balancing Mechanism Unit classification
All trading parties have two energy accounts (production and consumption) into which feed the physical flows of
Balancing Mechanism Units (BMUs) linked to the party. BMUs are the units of trade and settlement, used to account
for physical flows at smallest aggregation of independently controllable apparatus. Most large generation units are an
individual BMU, with small generators often aggregated within a supplier’s BMU. The linkage between BM Units,
production/consumption accounts and trading parties is summarised in Figure 19.
On any given settlement day BM Units also need to be registered as either production or consumption units (P/C
Status). This defines which Energy Account a given Unit’s energy production/consumption feeds into on said
settlement day (i.e. Production BM Units are linked with the Production Account and vice versa).
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Figure 19 – BM Units and Production/Consumption Accounts
Contracted energy
sale volume
nominated to
Production a/c
Production a/c
Consumption a/c
• Metered volume
• Metered volume
• Contracted volume
• Contracted volume
Production BM Unit
metered volume
Consumption BM
Unit metered volume
BM Unit 1
BM Unit 5
Energy sale contract
volume
If Generation
Capacity > Demand
Capacity, BM Unit
classed as
‘Production’
All metered volume
from ‘Production’ BM
Units is credited to
Production Account
Credited Energy
Volume
Contracted energy
purchase volume
nominated to
Consumption a/c
Trading party
BM Unit 2
BM Unit 3
BM Unit 4
Energy purchase
contract volume
If Generation
Capacity < Demand
Capacity, BM Unit
classed as
‘Consumption’
BM Unit 6
BM Unit 7
BM Unit 8
All metered volume
from ‘Consumption’
BM Units is credited
to Consumption
Account Credited
Energy Volume
There are several types of BM Unit, each representing different aspects of the system:




BM Units directly connected to the transmissions system (typically generation units);
BM Units embedded in a distribution system;
BM Units related to an interconnector; and
BM Units covering supply.
There is no specific category for storage and the existing definitions within the BSC would treat (at least some
categories of) storage as a generating unit, as illustrated through the reproduced definitions in Table 9. Distribution
connected storage would be treated as an embedded BM Unit. However, given that there will be energy flows into and
out of a storage BMU, arrangements more analogous to those in place for interconnector BMUs may be a more
appropriate reflection of the physical nature of a storage asset. The interconnector arrangements are summarised in
the box below.
Table 9 – BMU definitions relevant for treatment of storage
Term
Generating Unit
Definition

means any Apparatus which produces electricity
Apparatus

means all equipment in which electrical conductors are used or
supported or of which they form part
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Interconnector BMUs under the BSC
Given the two-way electricity flow from a storage device it can, to some degree, be likened to
the dynamics of an interconnector. It is thus worth considering BSC arrangements for
interconnectors and how this can potentially be applied to assist the future deployment of
storage.
Section K5 of the BSC sets out the following requirements for interconnectors:
The metering system must allow for quantities of imports and exports to be measured
separately.
An Interconnector Administrator and an Interconnector Error Administrator must be appointed.
An Interconnector BM unit is a notional BM unit.
Upon being appointed, an Interconnector Administrator is automatically allocated two BM units
(designated as a Production BM Unit and a Consumption BM unit). This is in contrast to other
apparatus/collections of apparatus where a single BM Unit is assigned.
In relation to Production Interconnector BM Units the value of demand capacity shall at all times
be zero.
In relation to a Consumption Interconnector BM Units the value of generation capacity shall at
all times be zero.
6.2.4
Implications of trading arrangements for value of flexibility
In addition to influencing participation in the wholesale market, the trading arrangements influence the value that
storage assets may realise through the market. The imbalance settlement arrangements are a particularly important
driver of value. The intention of electricity imbalance (or cashout) arrangements is to settle energy taken or produced
without a contract. Further details are provided in Annex C.2.2. But the current calculation methodology serves to
dampen cashout prices and so weaken the signals and incentives that they provide:



The current ‘main’ imbalance price is calculated on the basis of the weighted average of the 500 MWh most
expensive energy trades needed to balance the system. This approach serves to dampen cashout prices, as the
costs of more expensive balancing actions are muted through the averaging process. This creates a mismatch
between the costs of balancing the system at the margin and imbalance exposure for parties who are out of
balance. Therefore, the weighted average approach dampens cashout prices and the signals that they create for
parties to balance their positions.
The way in which the costs of STOR feed into cashout prices has a dampening effect on cashout prices. When
exercised through the Balancing Mechanism, utilisation fees do feed directly into cashout price calculation as
accepted offers. But the price levels are fixed in the tender process, well in advance of potential delivery, meaning
that they cannot reflect the underlying supply/demand fundamentals and system tightness in real-time. In periods
of tightness, Balancing Mechanism offers linked to STOR contracts are likely to displace other offers which are (a)
not ‘cross-subsidised’ by an availability payment and (b) likely to reflect increased scarcity value linked to system
tightness. Utilisation fees for non-Balancing Mechanism STOR are not reflected at all. Availability payments are
included in cashout prices in periods of historic utilisation of STOR through a Buy Price Adjuster (BPA), which is
an adder to the prices derived from other balancing actions. It is an imperfect proxy for when reserve is actually
used and valued most.
In extreme circumstances, the SO can instruct the Distribution Network Operators to reduce demand through
voltage reduction (brownouts) or disconnection (blackouts) in order to balance the system. These balancing
actions are not included in the calculation of cashout prices. As a result, cashout prices at periods of system
stress are dampened as they do not reflect the costs of these balancing actions.
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Overcoming these weaknesses will sharpen cashout prices and the incentives for parties to balance. This will increase
the value of flexible and reliable capacity, such as storage, which can help parties to balance their positions. This is
recognised by Ofgem in its Electricity Balancing Significant Code Review (EBSCR), which has led to the development
25
of a proposed package of reforms to the cashout arrangements outlined for consultation in July 2013 as follows:



to make cash-out prices more marginal by reducing the volume of actions on which the cash-out price is based to
1MWh (a ‘fully marginal’ cash-out price);
to improve pricing of reserve by amending the price of STOR actions in the cash-out price calculation such that
they are based on a Reserve Scarcity Pricing function; and
to introduce a cost in the cash-out arrangements for voltage control (brown-outs) and disconnection (black-outs)
emergency balancing actions.
In addition, Ofgem is proposing the adoption of a single cashout price for all imbalances in a given settlement period,
rather than the current dual price approach. Ofgem’s analysis suggested that the proposed reforms would make
cashout prices sharper and improve incentives for investments in flexible capacity.
6.3 Balancing services
6.3.1
Overview of balancing services
In the GB market, generators dispatch their plant to meet their contracted electricity sales. However, it is ultimately the
responsibility of National Grid to ensure that generation and demand are balanced at all times and in all locations. In
order to fulfil this duty, National Grid employs a range of tools. These tools (collectively known as Balancing or
Ancillary Services) can be broadly broken down as follows:



Frequency Response: the automatic provision of increased generation or demand reduction in response to a
drop in system frequency. This can be further subdivided into Primary and Secondary response:
o Primary response is defined as the sustained output from 10 seconds to 30 seconds following a loss of
0.8Hz.
o Secondary response is defined as the sustained output from 30 seconds to 30 minutes for a loss of
0.5Hz.
Reserve: the manual provision of increased generation or demand reduction over a period of minutes or hours in
response to an instruction from National Grid; and
System Security: the provision of generation or demand variation (i.e. increase or reduction as appropriate in the
specific circumstances) in order to ease local transmission constraints or other system security issues.
Figure 20 below provides an overview of balancing services provided by National Grid. Further details relating to
STOR, fast reserve and frequency response are provided in Annex D. Importantly, a number of these services can be
offered by non-BM Units, creating scope for participation by non-conventional source, potentially through an
aggregator.
25
‘Electricity Balancing Significant Code Review – Draft Policy Decision’, Ofgem, July 2013.
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Availability payment?
Holding/positional
payment?
Utilisation payment?






<240min
>120min



<2min
>15min



Provision perion
(minutes)
n/a



Response time
(seconds/minutes)
Balancing Mechanism
Minimum volume
(MW)
Available to demand
side non-BM Units?
Figure 20 – Categorisation of Balancing Services procured by National Grid
10
<2sec
n/a
3
<2sec
>30
3
<2sec
3
50

Frequency Response
Mandatory FR
Firm FR
FCDM
Commercial FR




Reserve
STOR
Warming / BM Start UP
Fast start
Fast Reserve
Demand Management





dependent on circumstances
System security
Constraint management
Intertrips


dependent on circumstances
dependent on circumstances
Source: National Grid and Pöyry Management Consulting analysis
National Grid, in accordance with its Procurement Principles, is required to procure Balancing Services in an economic
and non-discriminatory manner. In order to do so, it defines a number of different services based on technical
parameters such as speed of response to instruction, as well as speed, duration, repeatability, scale and reliability of
provision of generation. It has discretion to procure a portfolio of these services in the mix it feels is both technically
required and most economic.
These services have tended to be linked to historical requirements and the different technical characteristics of
generating technologies prevailing at that time. This historic perspective risks overlooking new system needs and the
offerings of new technologies. However, there has been recent evolution of services (as discussed below) and the
Procurement Principles allow provide flexibility for non-standardised services to be procured under bespoke contractual
arrangements.
An additional factor which warrants consideration in the context of balancing services provision is the associated
carbon emissions. The utilisation prices for fossil fuel providers will include the carbon price (EU ETS and carbon
prices support), but this does not reflect the overall cost of carbon. There may be scope, therefore, for a fuller account
to be taken of the associated cost of carbon during assessment of balancing service tenders.
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6.3.2
Evolution of services
There has been development of balancing services to open up potential for and to recognise the potential contribution
of non-conventional providers, including storage:



STOR is open to both BM participants (generally transmission connected generation from large power station
sites) and non-BM participants (generally small transmission or distribution connected generation and demand).
Non-BM providers are able to provide a ‘flexible’ service, with scope for variation in terms of the number of hours
for which they must be available and the timing of them, relative to the ‘committed’ service provided by BM
participants. This is beneficial to storage providers given potential discharge duration and recharging timescales.
Also, providers under the minimum 3MW capacity requirement can be aggregated into a combined offering. The
‘flexible’ service opens up the STOR market to a wider range of potential providers and enhances the ability for
non-conventional sources of capacity, such as storage, to participate and realise value.
More recently, NG has announced that it is considering introducing an aggregated fast reserve service from nonBM providers. The aggregated package must meet the standard minimum service provision (50MW delivered
within 2 minutes). This trial opens up the potential for non-conventional providers, including storage, to offer fast
reserve as part of an aggregated offering.
NG has also proposed revisions to the firm frequency response service, including the introduction of a week-ahead
tender time frame (intended to overcome longer-term forecasting limitations) and the introduction of aggregation.
Both initiatives have the potential to enhance participation from non-conventional service providers.
Ongoing evolution of the suite of balancing services is an important step in ensuring that appropriate services exist for
the future system challenges and that the capabilities of non-conventional technologies are incorporated in an
appropriate manner.
6.4 Capacity market
6.4.1
Overview of proposed capacity market
DECC has been progressing Electricity Market Reform (EMR) proposals for several years as a means to deliver its
objectives of ensuring a secure electricity supply and sufficient investment in sustainable low-carbon technologies,
while maximising benefits and minimising costs to taxpayers and consumers. The EMR package is summarised in
Annex D. The key element of the package for ensuring a secure electricity supply is the proposed introduction of a
Capacity Market.
The aim of the Capacity Market is to deliver generation adequacy. It offers capacity providers a capacity payment
revenue stream, in return for which they commit to deliver energy in periods of system stress or face exposure to
penalties if they fail to deliver.
Capacity contracts will be allocated to providers through auctions intended to secure a capacity requirement needed to
meet a 3-hour loss of load expectation reliability standard. The Capacity Market is intended to be technology neutral
across generation, storage and demand side providers (and, in time, interconnected capacity)and to allow new entrants
and existing capacity to participate. The auction clearing price forms the basis of the capacity payment to successful
auction participants. The first auction is expected to run in 2014 for delivery of capacity from 1 October 2018 to 30
September 2019, subject to State Aid clearance. In addition, auctions will be held one year ahead of delivery for
26
demand side response (including embedded generation and smaller storage ), with the first auction taking place in
2015, for delivery in 2016/17.
Certain elements of the current design proposals influence the ability of storage to participate in the Capacity Market.
27
The sections below are based on the capacity market proposals specified in October 2013 .
26
27
Precisely what is meant by ‘smaller storage’ is unclear.
https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/249565/capacity_market_rules_consultation_draft.pdf
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6.4.2
Storage is eligible to participate either directly or indirectly
As mentioned above, the intention is for storage to participate in the Capacity Market on an equal footing with other
sources of capacity. Indeed, the auction to be held one year ahead of delivery is specifically intended for storage,
alongside demand side participation, and it can also bid into the four year-ahead auction. The 2MW de-minimis size
threshold may exclude some smaller capacity projects from direct participation, but involvement through aggregation
with other capacity is possible.
However, the capacity that storage can offer into the Capacity Market will be limited to the export capacity only. The
impact of storage reducing imports during charging will not be factored into capacity agreements, meaning that
capacity payments cannot be earned for the full ‘swing’ capacity. Storage will, however, be entitled to over-delivery
payments if it stops importing at a time of system stress.
6.4.3
Nature of capacity obligation appears prohibitive for many
Parties who are successful in an auction are awarded a capacity contract. This entitles them to the capacity payment
(based on the auction clearing price) while requiring them to deliver energy in line with the underlying capacity
obligation in system stress periods. Failure to deliver will result in a penalty.
System stress events are defined as any settlement periods in which either voltage control or controlled load shedding
are experienced for a period of 15 minutes or longer. To allow market participants to manage the risk of exposure to
penalties, the System Operator will issue a Capacity Market Warning (CMW) at least 4 hours ahead of an anticipated
system stress event. This is intended to give capacity providers 4 hours in which to respond. Contracted providers not
delivering in line with their obligations 4 hours following a CMW will be liable to financial penalties. If a stress event
occurs unexpectedly without the provision of a CMW or before the 4 hour window has elapsed, no penalties will apply
for the relevant periods.
A key issue is that the period for which a CMW may apply, once issued, is undefined. The CMW can remain in place
until either:


the end of the day of issue in the event that a system stress event has not occurred on the day of CMW issue; or
the end of the day on which the system stress event ends in the event that a system stress event has occurred on
the day of CMW issue.
Therefore, there is no defined time limit over which delivery must be maintained, making the obligation to deliver
energy open-ended in nature. This is a problem for storage as discharge duration is limited. If fully discharged before
the end of the period affected by a CMW, the storage device will face exposure to potentially substantial penalties
equivalent to the volume of under-delivery multiplied by a price linked to Value of Lost Load (VoLL) (~£17,000/MWh) up
to a penalty cap of 100% of the annual capacity payment. This is a significant liability to take on which is likely to serve
as a deterrent from participation for projects with shorter discharge durations.
Penalty exposure could be mitigated by offering less than the full capacity into the market (i.e. self de-rating) which will
allow a lower volume of delivery to be maintained for a longer duration. However, this undermines the true capacity
that storage can offer and compromises the ability for storage to capture its true value. Another option for mitigating
penalty risk in the event of an extended CMW period is to participate in secondary trading to buy delivery of your
obligation from another provider. However, this is likely to be very costly given that the system is expected to be very
tight and so available capacity to take on the obligation will be limited, if available at all. Reliance on secondary
trading, certainly during the early years of the Capacity Market when the secondary market will be embryonic at best, is
unlikely to offer a viable route for mitigating non-delivery risk.
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6.5 Levy Exempt Certificates
6.5.1
Overview
As part of a range of measures designed to help the UK meet its commitment to reduce greenhouse gas emissions,
the UK Government introduced the Climate Change Levy (CCL) on commercial and industrial energy users in April
2001. CCL is an energy tax administered by HM Revenues & Customs (HMRC), under primary legislation introduced
through the Finance Act 2000. It is levied on energy consumed by industrial and commercial users (but not domestic
consumers). CCL rates are set annually in the Chancellor’s Budget Statement.
Electricity generated from renewable sources is exempt from CCL and most renewable technologies are eligible for
LECs. Eligible renewable generators may claim a LEC for each MWh of renewable electricity, and a LEC serves as
evidence that the associated electricity is exempt from CCL. The main exception is Hydro generation with a capacity
greater than 10MW. Hydro aside, the CCL exemption is available to all technologies eligible for ROCs, plus renewable
generation generated overseas (if consumed in the UK) and the biomass fraction of energy from waste generation.
In order for a renewable generator to be issued with LECs:



the electricity must be sold to a non-domestic end user in the UK either directly to the customer or indirectly via a
licensed supplier;
a ‘paper trail’ must be in place to demonstrate that the quantity of LEC qualifying electricity supplied to final
consumers matches that generated; and
generation data must be submitted to Ofgem within two months of generation.
Electricity suppliers can avoid paying CCL by purchasing a LEC from a renewable generator. The CCL exemption
value is realised through the trading of Levy Exemption Certificates (LECs), although the certificates cannot be
unbundled from, and have to be sold alongside, the electricity from which they were generated.
6.5.2
Relevance for storage
28
The treatment of storage under the CCL is unclear. The Statutory Instrument that defines the CCL framework
defines ‘renewable sources’ of energy as being ‘sources of energy other than fossil fuel or nuclear fuel and includes
waste provided that it is not waste with an energy content 90 per cent or more of which is derived from fossil fuel’.
This may give latitude for storage qualifying as a renewable source of energy, as it is not fossil fuel or nuclear.
However, this then leads to another question.
The SI states that ‘the amount of a supply of renewable source electricity is to be calculated at the point at which such
electricity is first delivered from a generating station to a distribution or transmission system within the United Kingdom
(excluding territorial waters)’. This confirms that a LEC is allocated at the original point of generation. As export from
storage relies first on import of existing generation output for which, if it was from a renewable source, a LEC has
already been issued, issuing a LEC at the point of export from storage would be double counting. This could suggest
that storage should not qualify for LECs.
However, linking this back to the discussion in Section 5.1, in the absence of an explicit definition of storage the default
position is that energy storage is treated as a subset of generation. If this holds in the context of the CCL, then it could
be argued that export from a storage device could be considered as a point of origin for generation.
This serves to highlight the lack of clarity regarding the treatment of storage under the CCL and so the ability or
otherwise for storage to qualify for LECs.
28
The Climate Change Levy (General) Regulations 2001.
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6.6 Issues linked to value realisation
There are multiple sources of value for distribution connected storage, a number of which relate to participation in
market activities. There are a number of aspects of the various market arrangements which affect the ability for
distribution connected storage to realise value:



Distribution connected storage can participate in the wholesale market, most likely through inclusion in a supplier’s
portfolio. However, there is scope for consideration of the treatment of storage within the BM Unit classification
options and its treatment within the settlement. Additionally, the possibility of DNOs becoming trading parties
needs consideration.
There are opportunities for participation in balancing service provision, with evolution of the products enhancing
this. But the underlying nature of service specifications and requirements remains influenced by historical
technologies and capabilities and there is scope for further evolution.
The opportunity for storage to realise value from the proposed capacity market appear limited given the openended nature of the obligation to deliver energy and the potential penalty exposure that this creates.
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7 Conclusions
7.1 Key observations
Electricity storage projects are trying to find a way to work within a regulatory framework that was not really developed
with storage in mind. The existing frameworks are a product of the main objectives for the sector at the time they were
created, namely the progression of liberalisation and promotion of competition in the traditional activities within the
sector. The arrangements have been effective in delivering these goals. But as the challenges facing the sector
evolve and the potential role for storage in helping to manage the system increases, it is important to appraise whether
the regulatory framework itself is presenting issues for increased deployment of storage.
This review has identified that there are several issues within the legal and regulatory framework which affect the
deployment and utilisation of distribution connected electricity storage within the GB market:
1.
2.
3.
4.
Default treatment of storage as a subset of generation creates uncertainty and raises potential issues.
But generation licence exemption route does provide flexibility to progress distribution connected storage projects
of appropriate size in a manner consistent with unbundling requirements.
De minimis business restrictions do place a loose limit on deployment by DNOs, if storage continues to be classed
as generation.
But, possible application and operation of assets is affected though by the need to ensure that competition in
generation and supply is not distorted.
These regulatory issues have differing implications for the five SNS business models. They are of greater significance
for the business models which entail DNO ownership and operation of the storage asset. This stems principally from
the concern that DNO activity in storage projects could distort competition in generation and supply activities. The
qualitative assessment of the implications of these issues for the business models is shown in Table 10.
DNO-led development of smaller scale storage projects is, therefore, possible within the regulatory framework. But,
ensuring that such activity avoids distorting competition in generation and supply is a major factor which appears to
block operation of the assets by DNOs under the current framework.
Table 10 – Importance of regulatory issues for SNS business models
Issue
DNO merchant
DSO
DNO contracted
Contracted
services
Charging
incentives
2
2
1
0
0
4
4
2
2
0
2
2
1
0
0
1
1
1
0
0
4
4
4
2
0
Default treatment
as generation
Distortion of
competition
Unbundling
requirements
De minimis
restrictions
Assessment of
economic benefits
Key: Low importance
01234
High importance
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7.2 Next steps
The next phase of this work is to progress from issue identification to development of potential solutions. The issues
that have been identified to date will form the starting point. Focus areas include options for:




clarifying/modifying treatment of electricity storage within the framework, including classification and requirements
for licences to operate;
enabling DNO operation of electricity storage assets for balancing purposes in a transparent and non-distortionary
manner, delivering consistency with unbundling requirements;
considering the potential for GB DNOs to trade in a non-speculative manner under a model similar that that under
which National Grid fulfils its system operator role; and
including storage investments appropriately within price controls.
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Annex A – EU and GB Legal framework overview
A.1
European context
A.1.1
Overarching Treaties
The Treaty of Lisbon places energy at the heart of European activity. It effectively gives it a new legal basis which it
lacked in the previous treaties. Article 194 of the Treaty on the Functioning of the European Union (TFEU) sets out the
overarching objectives for EU energy policy. Objectives expressed in Article 194 are as follows:
1.
2.
3.
4.
ensure the functioning of the energy market;
ensure security of energy supply in the Union;
promote energy efficiency and energy saving and the development of new and renewable forms of energy; and
promote the interconnection of energy networks.
The aims of the policy are supported by market-based tools (mainly taxes, subsidies and the CO2 emissions trading
scheme), by developing energy technologies (especially technologies for energy efficiency and renewable or lowcarbon energy) and by Community financial instruments. Furthermore, in December 2008 the EU adopted a series of
measures with the objective of reducing the EU’s contribution to global warming and guaranteeing energy supply.
A.1.2
Liberalisation and internal energy market
29
The development of a single European energy market began in 1996, with the establishment of Directive 96/92/EC ,
subsequently referred to as the ‘first energy package’. In pursuit of liberalisation and enhanced competition, Directive
96/92/EC required:



accounting separation for different activities within vertically integrated entities;
market opening in the supply sector; and
non-discriminatory access to transmission and distribution systems.
30
Directive 96/92/EC was followed in 2003 by the ‘second energy package’; Directive 2003/54/EC . This strengthened
and built upon the provisions of its predecessor with requirements for:


legal separation for different activities within vertically integrated entities to ensure independence between
distribution and transmission operators and any generation/supply companies; and
third party access to networks based on non-discriminatory and cost-reflective tariffs.
The second package has now been superseded by the ‘third energy package’, which is embodied within Directive
31
2009/72/EC , also known as the ‘Electricity Directive’, which pushes market integration further. It introduced
requirements for:

29
separation of transmission system operation from generation and supply activities through either ownership
unbundling or transfer of system operation control to an independent system operator;
‘Directive 96/92/EC of the European Parliament and of the Council of 19 December 1996 concerning common rules for the internal market in
electricity’ http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:31996L0092:EN:HTML
30
‘Directive 2003/54/EC of the European Parliament and of the Council of 26 June 2003 concerning common rules for the internal market in
electricity and repealing Directive 96/92/EC’. http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2003:176:0037:0037:EN:PDF
31
‘Directive 2009/72/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in
electricity and repealing Directive 2003/54/EC’. http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2009:211:0055:0093:EN:PDF
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
non-discriminatory access for third parties to retail distribution networks in both electricity and gas sectors and to
storage capacities in the case of gas;
establishment of a single National Regulatory Authority independent from government and from any other public or
private entity;
establishment of the Agency for the Cooperation of Energy Regulators (ACER) with the aim of exercising at
Community level the tasks performed by the Member States’ regulatory authorities (Regulation (EC) No
32
713/2009 ); and
adequate social protection without distortions of the market’s competitiveness.
a framework for cross-border exchanges in electricity in order to alleviate barriers to competition in the internal
market in electricity was laid down in Regulation (EC) No 714/2009.




Figure 21 – Overview of EU’s third package legislation
A.1.3
Security of supply
33
EU security of supply policy is embodied in Directive 2005/89/EC concerning measures to safeguard security of
electricity supply and infrastructure investment. According to Directive 2005/89/EC, Member States must define
general, transparent and non-discriminatory policies on security of electricity supply compatible with the requirements
of a competitive single market for electricity, taking into account the need to:






ensure continuity of electricity supplies;
study the internal market and the possibilities for cross-border cooperation in relation to security of electricity
supply;
reduce the long-term effects of growth of electricity demand;
introduce a degree of diversity in electricity generation in order to ensure a reasonable balance between different
primary fuels;
promote energy efficiency and the use of new technologies; and
continuously renew transmission and distribution networks to maintain performance.
They must define and publish the role and responsibilities of competent authorities and different players in the market.
Transmission network operators are required to set minimum rules and obligations to ensure continuous operation of
the transmission and, where appropriate, the distribution network under foreseeable circumstances.
32
Regulation (EC) No 713/2009 of the European Parliament and of the Council of 13 July 2009 establishing an Agency for the Cooperation of
Energy Regulators http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:32009R0713:en:NOT
33
‘Directive 2005/89/EC of the European Parliament and of the Council of 18 January 2006 concerning measures to safeguard security of
electricity supply and infrastructure investment’ http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:32005L0089:EN:NOT
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In order to balance supply and demand, Member States need to:




encourage the establishment of wholesale markets;
require network operators to ensure that an appropriate level of generation reserve capacity is maintained;
facilitate the development of new generation capacity; and
promote energy conservation and technology for demand management in real time.
In addition, a framework must be laid down for providing information to network operators which facilitates investment.
Finally, Member States or competent authorities, in cooperation with transmission network operators, must prepare a
report on security of supply, as provided for in the directive on the internal electricity market.
A.1.4
Trans-European energy infrastructure
Europe’s energy infrastructure needs to be modernised and interconnected across borders, in order to support the
EU’s climate and renewable energy targets, as well as the core energy policy objectives of competitiveness,
sustainability and security of supply. To ensure a timely development and the interoperability of trans-European
34
energy networks, the Regulation on guidelines for trans-European energy infrastructure (Regulation (EU) 347/2013 )
was adopted on 21 March 2013 and entered into force on 1 June 2013, repealing Decision No 1364/2006/EC and
amending Regulations (EC) No 713/2009, (EC) No 714/2009 and (EC).
The Regulation defines 12 strategic trans-European energy infrastructure priorities the implementation of which by
2020 is vital for the achievement of the union’s energy and climate policy objectives. These priorities cover different
geographic regions and specific areas in the fields of electricity, gas and oil, such as electricity transmission and
storage, gas transmission, storage and liquefied or compressed natural gas infrastructure, smart grids, electricity
highways, carbon dioxide transport and oil infrastructure.
Member states will propose “Projects of Common Interest” (so called PCIs) contributing to the development of the
trans-European energy infrastructure priority corridors and areas. In order to achieve this goal the regulation provides
criteria to identify such projects of common interest (i.e. cross-border projects or projects which benefit two or more
Member States), which may be eligible for EU funding under the ‘Connecting Europe Facility’ financing instrument. The
regulation also provides for new, more transparent and accelerated procedures to grant permits for these projects,
which should generally not exceed 3.5 years. In addition, it lays down rules on the possible cross-border allocation of
construction costs for infrastructure projects of common interest.
The Commission aimed at adopting a first EU-wide list of projects of common interest on the basis of regional lists by
30 September 2013. Subsequent lists are to be drawn up every two years. Six months after the adoption of the first list,
the Commission will establish a publicly accessible infrastructure transparency platform containing information on
projects of common interest and, no later than 2017, a report will be published on the implementation of these projects.
34
Regulation (EU) 347/2013 of the European Parliament and of the Council of 17 April 2013 on guidelines for trans-European energy
infrastructure and repealing Decision No 1364/2006/EC and amending Regulations (EC) No 713/2009, (EC) No 714/2009 and (EC) No
715/2009 http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2013:115:0039:0075:EN:PDF
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A.1.5
Renewable Energy
35
Directive 2009/28/EC on the promotion of the use of energy from renewable sources (also known as the ‘Renewables
Directive’), establishes a common framework for the production and promotion of energy from renewable sources as
part of the EU 2020 Climate & Energy Package.
Each Member State has a target calculated according to the share of energy from renewable sources in its gross final
consumption for 2020. This target is in line with the overall '20-20-20' goal for the Community. Moreover, the share of
energy from renewable sources in the transport sector must amount to at least 10 % of final energy consumption in the
sector by 2020. Countries are to establish National Renewable Energy Action Plans (NREAPS) which set the share of
renewable energy consumed for electricity and heating, as well as for transport for 2020. The national action plans
also include the necessary procedures for reform in planning, pricing and network access to promote the development
of renewable energy sources. A template for National Renewable Energy Action Plans under Directive 2009/28/EC
36
was created with the Commission Decision 2009/548/EC in June 2009.
Cooperation between Member States for the achievement of the targets is provided for, as Member states can
‘exchange’ an amount of renewable energy by agreeing on a statistical transfer. Therefore, surplus or deficit of
renewable energy generation are exchanged between Member States by subtracting the corresponding amount from
the statistical figures of the ‘exporting’ member state and adding it to the official RES statistics of the ‘importing’
member state. Each Member State must be able to guarantee the origin of electricity, heating and cooling produced
from renewable energy sources.
Transmission and distribution network access is a prerequisite for the development of renewable energy sources.
Member States should therefore ensure that operators guarantee the transport and distribution of electricity from
renewable sources and provide for priority access for this type of energy.
A.1.6
EU Emissions Trading System
37
The EU Emissions Trading System (ETS) was introduced with Directive 2003/87/EC which came into force on 25
October 2003 and established a scheme for greenhouse gas emission allowance trading within the Community. The
38
directive was subsequently amended in 2004 with the ‘Linking Directive’ (2004/101/EC) to enable Member States to
allow operators to use credits obtained through Kyoto Mechanisms (CERs - Certified Emissions Reductions and ERUs
- Emission Reduction Units). In 2008 it was amended again to include aviation starting from 2012 (‘Aviation Directive’
39)
40
2008/101/EC . The latest amendment in the EU ETS legislation came in April 2009, Directive 2009/29/EC (Phase
35
Directive 2009/28/EC of the European Parliament and of the Council of 23 April 2009 on the promotion of the use of energy from renewable
sources and amending and subsequently repealing Directives 2001/77/EC and 2003/30/EC http://eurlex.europa.eu/Notice.do?val=496661:cs&lang=en&list=506182:cs,503937:cs,497602:cs,496661:cs,486724:cs,486634:cs,&pos=4&page=1&n
bl=6&pgs=10&hwords=
36
Commission Decision 2009/548/EC of 30 June 2009 establishing a template for National Renewable Energy Action Plans under Directive
2009/28/EC of the European Parliament and of the Council http://eurlex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:32009D0548:EN:NOT
37
‘Directive 2003/87/EC of the European Parliament and of the Council of 13 October 2003 establishing a scheme for greenhouse gas
emission allowance trading within the Community and amending Council Directive 96/61/EC’ http://eurlex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:02003L0087-20090625:EN:NOT
38
‘Directive 2004/101/EC of the European Parliament and of the Council of 27 October 2004 amending Directive 2003/87/EC establishing a
scheme for greenhouse gas emission allowance trading within the Community, in respect of the Kyoto Protocol's project mechanisms’
http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:32004L0101:en:NOT
39
Directive 2008/101/EC of the European Parliament and of the Council of 19 November 2008 amending Directive 2003/87/EC so as to include
aviation activities in the scheme for greenhouse gas emission allowance trading within the Community http://eurlex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:32008L0101:EN:NOT
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III) to improve and extend the trading scheme. The revised EU ETS Directive formed part of the EU 2020 Climate &
Energy Package agreed in December 2008.
A.1.7
Energy Efficiency
41,
In March 2011 the EC adopted the Communication ‘Energy Efficiency Plan 2011’
proposing a set of concrete
measures to create energy efficiency benefits. Following this communication, the EU published the ‘Energy Efficiency
42
Directive’ (2012/27/EU ) in 2012. The directive’s aim is to create an effective common framework of measures to
promote energy efficiency within the EU in order to achieve the 20 20 20 target of 20% reduction in energy
consumption by 2020 and to lay the foundations for further improvement in this area beyond 2020. Member States are
required to increase their energy efficiency efforts across the entire energy chain, from generation to distribution and
final consumption. The directive is expected to help in overcoming current impediments and addressing market
failures related to energy efficiency, providing for the establishment of indicative national energy efficiency targets for
2020.
EU’s 2020 energy efficiency consumption target was legally defined and quantified at 1,483Mtoe of primary energy or
no more than 1,086Mtoe of final energy (revised after the accession of Croatia). Member states were obliged to set an
indicative national energy efficiency target for 2020 by 2013. Moreover each country has the obligation to achieve
certain amount of final energy savings over the obligation period (01 January 2014 – 31 December 2020) by using
energy efficiency obligations schemes or other targeted policy measures to drive energy efficiency improvements in
households, industries and transport sectors.
A.2
GB context
A.2.1
Liberalisation and internal energy market
A.2.1.1 Liberalisation
The GB market is the oldest liberalised electricity market in the EU, with the first steps taken in the Electricity Act of
1989, and privatisation and the formation of the Electricity Pool in 1990. Since then, both primary and secondary
regulation has shaped and developed the market, including the introduction of NETA in 2001. NETA created a
wholesale market open to all generation and demand through bilateral Over the Counter trades and power exchanges.
The Energy Act 2004 provided powers in relation to the introduction of a new system of electricity transmission access
and settlement across England, Wales and Scotland (BETTA) which came into effect in April 2005.
The Electricity Act 1989 provided for the privatisation of the electricity supply industry in Great Britain and the
establishment of a licensing regime and an industry regulator, the Office of Electricity Regulation (OFFER). The
Utilities Act 2000 reformed the regulatory regime for electricity and downstream gas in Great Britain. In particular, it
formalised the merger of OFFER and Ofgas into a combined regulator, Ofgem, and amended the statutory duties of the
regulator. Subsequent legislation has reinforced the powers of Ofgem, most notably with the Energy Act 2010, which
enhanced the powers of the regulator to deal with exploitation of electricity distribution constraints by generators and
also increased its power to fine companies. In the same Act Ofgem’s objectives on tackling climate change were
clarified, ensuring secure energy supplies and the role of measures other than competition in protecting the interests of
consumers.
40
Directive 2009/29/EC of the European Parliament and of the Council of 23 April 2009 amending Directive 2003/87/EC so as to improve and
extend the greenhouse gas emission allowance trading scheme of the Community http://eurlex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:32009L0029:EN:NOT
41
Communication ‘Energy Efficiency Plan 2011’ [COM/2011/0109] http://eurlex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:52011DC0109:EN:HTML:NOT
42
Directive 2012/27/EU of the European Parliament and of the Council of 25 October 2012 on energy efficiency, amending Directives
2009/125/EC and 2010/30/EU and repealing Directives 2004/8/EC and 2006/32/EC http://eurlex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:32012L0027:EN:HTML:NOT
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A.2.1.2 Internal energy market
The ‘Electricity Directive’ (2009/72/EC) and the ‘Gas Directive (2009/73/EC) have been fully implemented in Great
Britain through the Electricity and Gas (Internal Markets) Regulations 2011. The regulations designate Ofgem as the
National Regulatory Authority (NRA) for Great Britain, enhance the level of information available to consumers, reduce
switching time between suppliers, change the license modification process and create a new appeal procedure.
Greater regulation is introduced for those exempt from the requirements to hold a distribution or supply license. Other
changes made include the full ownership unbundling, the Independent System Operator (ISO) model and the
‘unbundling derogation for arrangements providing greater independence than the Independent Transmission Operator
(ITO) model’ available in the electricity and gas markets.
A.2.2
Renewable
energy
The Renewables Obligation (RO) is currently the main support scheme for large scale renewable electricity in the UK.
It is a green certificate scheme providing support on top of any revenues gained from the sale of wholesale electricity.
It has been in existence since April 2002 and lasts until 31 March 2037. Since its introduction it has been adapted
significantly with a movement to technology differentiated support through ‘banding’, and a movement to more stable
certificate prices through the introduction of the ‘headroom’ mechanism.
There are three RO schemes operating in the UK, the England and Wales Renewables Obligation (RO), the
Renewables Obligation Scotland (ROS) and the Northern Ireland Renewables Obligation (NIRO). The schemes
generally work as a single unit, with the green certificates known as Renewables Obligation Certificates (ROCs)
interchangeable between them.
The Department for Energy and Climate Change (DECC), alongside the Scottish Executive (SE) and Department for
Enterprise, Trade and Industry Northern Ireland (DETINI), is responsible for setting the rules of the scheme including
the Obligations on suppliers. The primary legislation, setting out the high level objectives of the scheme is in the
Energy Act 2008 which amends the Electricity Act 1989. The secondary legislation, with the detailed rules of the
43
scheme, is the Renewables Obligation Order 2009 (as amended in 2010 and 2011) .
Ofgem is responsible for the administration of all three schemes including accrediting generating stations, issuing
ROCs and ensuring suppliers comply with their Obligations. It has published a guidance document for generators
44
which sets out its administrative procedures for the implementation of the RO . More information on the operation of
the RO is provided in Ofgem’s annual reports. These include details of generating stations accredited, ROCs issued,
supplier’s Obligations and supplier’s compliance with their Obligations.
As part of the Energy Act 2013, a new support mechanism for renewable generation has been introduced. The Feedin Tariff with Contracts for Difference (FiT CfD) will initially operate alongside the Renewables Obligation, subsequently
replacing the RO once this closes to new generation in 2017. Figure 22 shows the timeline of the transition to the
Feed-in Tariff with Contracts for Difference scheme.
43
44
Statutory Instrument 2009 no.785; ‘Statutory Instrument 2010 no.1107’ and Statutory Instrument 2011 no.984’.
Renewables Obligation: Guidance for Generators 2013. Ofgem, May 2013.
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Figure 22 – Commissioning date will determine eligibility for support scheme
The Feed-in Tariff will operate as a Contract for Difference around the wholesale electricity price, where the low carbon
generator receives revenue from the wholesale market for its output and either receives or makes a payment based on
the difference between a reference market price index and the strike price (tariff) agreed in its contract. Payments will
be made on metered output, with payments to a generator capped at their respective strike price to avoid increasingly
negative prices.
A.2.3
Climate change
The UK is the first country to introduce a long-term legally-binding framework nationally to tackle the dangers of climate
change, through the Climate Change Act 2008. The Act provided the UK with a legal framework, including a long-term
target for emissions in 2050, 5-year carbon budgets on track to that target, and the development of a climate change
adaptation plan. The Climate Change Act 2008 also established the Committee on Climate Change (CCC), an
independent, statutory public body, tasked with assessing how the UK can best achieve its emissions reduction targets
for 2020 and 2050 and the progress that is being made toward meeting statutory carbon targets. The Committee on
Climate Change is required to advise the Government on the levels of carbon budgets to be set, the balance between
domestic emissions reductions and the use of carbon credits, and whether the 2050 target should be increased. The
CCC is also required to publish annual progress reports.
The Greenhouse Gas Emissions Trading Scheme Regulations 2003 transposed the EU ETS into UK law and were
subsequently amended and replaced by the Greenhouse Gas Emissions Trading Scheme Regulations 2005. Phase III
of the EU ETS, which runs from 2013 to 2020, started in January 2013. Phase III has seen the introduction of a
number of measures aiming to broaden and strengthen the environmental ambitions of the scheme, as set out in the
revised EU ETS Directive (2009/29/EC). The Greenhouse Gas Emissions Trading Scheme Regulations 2012 (the
2012 Regulations) implemented these measures in the UK by fully transposing the revised EU ETS Directive into
domestic law. These Regulations also consolidated and replaced previous EU ETS legislation.
The Climate Change Act 2008 provided the government with powers to establish additional domestic trading scheme
by means of secondary legislation. Under these powers, the Carbon Reduction Commitment Energy Efficiency
Scheme Order 2010 requires large public and private sector organisations outside the EU ETS which consume
electricity above a certain threshold to purchase a new form of allowance. The introductory phase of the scheme runs
from April 2010 to April 2014, when Phase 2 will begin.
A.2.4
Energy efficiency
The Energy Act 2009 introduced the Green Deal, the government’s flagship policy to improve energy efficiency in
British domestic and non-domestic buildings. The Green Deal provides a finance mechanism for installing energy
efficient upgrades, giving households and businesses the opportunity to borrow up to £10,000 and repay the loans over
25 years via energy bills. The aim of the policy is to remove the upfront cost of installing energy efficiency
improvements, which renders the installation decision unattractive for most households, since related energy savings
occur over the course of several years.
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The Energy Company Obligation (ECO) was another measure introduced with the Energy Act 2009 to complement the
Green Deal and alleviate fuel poverty by providing low income and vulnerable households with subsidies to install
insulation and heating measures. The ECO replaced the Carbon Emissions Reduction Target (CERT) and Community
Savings Programme (CESP) which ended in 31 December 2012.
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Annex B – Generation requirements
B.1
Introduction
Requirements and obligations for generators depend upon a number of characteristics. These include:



whether the generator is classed as licence exempt;
the size of the generator; and
the treatment of the generator under the Connection and Use of System Code (CUSC) and the type of bilateral
connection agreement that the generator may have to sign with National Grid.
B.2
Licensed versus licence-exempt
45
In general, a power station requires a licence in order to generate electricity for purposes of supplying consumers .
Exemptions from this requirement can be granted to classes of generators or to particular generators in specific
46
circumstances . The circumstances in which class exemptions apply are as follows:

Exemptible as offshore generator:



Exemptible as small generator:



if output to the total system (GB transmission system and all distribution systems) is less than
10MW; or
if output to the total system is less than 50MW and the declared net capacity of the power station is
less than 100MW.
Exemptible as generator not exceeding 100MW:



if the power station is situated on an offshore installation; and
the power station only supplies electricity to offshore installations.
if the power station was connected to the total system on (or before) 30 September 2000; and
output to the total system is less than 100MW.
Exemptible as never subject to central dispatch:


if the power station was connected to the total system on (or before) 30 September 2000; and
the power station has never been subject to central dispatch.
Additionally, power stations which do not fall into any of the exemption classes listed above may apply to DECC to
seek an individual exemption. Power stations capable of exporting between 50MW and 100MW to the total system
that connected after 30 September 2000 are generally granted exemption via this route. If the power station is capable
of providing 100MW or more to the total system, it must be licensed (unless never subjected to central dispatch, as
above).
B.3
Size categorisations
The Grid Code specifies three categories of power station size which vary according to geographic location of
connection:

Large:
o
o
45
46
>100MW in England and Wales;
>30MW in South Scotland (Scottish Power’s transmission area); or
Section 4 of the Electricity Act (1989).
Class exemptions are specified in ‘The Electricity (Class Exemptions from the Requirement for a Licence) Order 2001’.
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

o
Medium:
o
o
Small:
o
o
o
>10MW in North Scotland (Scottish Hydro-Electric’s transmission area).
50MW to 100MW in England and Wales; and
N/A in Scotland.
<50MW in England and Wales;
<30MW in South Scotland (Scottish Power’s transmission area); or
<10MW in North Scotland (Scottish Hydro-Electric’s transmission area).
Within these size categorisations, National Grid refers to licence-exempt embedded generators as:



Embedded Exemptible Large Power Stations (EELPS);
Embedded Exemptible Medium Power Stations (EEMPS); and
Embedded Exemptible Small Power Stations (EESPS).
The treatment of power stations under the CUSC differs depending upon its licence status, size categorisation and
point of connection, as discussed below.
B.4
CUSC and Bilateral Agreements
After accession to the CUSC, the following generators must enter into some form of Bilateral Agreement with National
Grid, as follows:



transmission connected generators (licensed and licence-exempt alike) must enter into a Bilateral Connection
Agreement (BCA) with National Grid;
embedded, licensed generators are required to enter into a Bilateral Embedded Generation Agreement (BEGA);
and
EELPS can choose to sign a BEGA or a Bilateral Embedded Licence exemptible Large power station Agreement
(BELLA) with National Grid.
EEMPS and EESPS are not normally required to enter into a Bilateral Agreement with National Grid. However, if they
do choose to enter directly into a Bilateral Agreement with National Grid (rather than allocating their output to another
party) they must enter into a BEGA. Table 11 summarises the high-level implications attached to the different Bilateral
Agreements.
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Table 11 – Implications of different Bilateral Agreements
Implications
Grid Code
BCA
Requires full compliance
with the GB Grid Code
BEGA
Requires full compliance
with the GB Grid Code
(subject to any
approved derogations)
Use of system
Confers financially-firm transmission access rights
and so requires payment for use of the GB
transmission system charges (TNUoS and BSUoS)
for licensable generation
Connection
Requires payment for
connection to the GB
transmission system
BELLA
Requires partial
compliance with the
Grid Code
Does not confer
financially-firm
transmission access
rights or liability for
generator charges
(TNUoS and BSUoS)
Does not require connection to the GB transmission
system and so does not require payment for
connection to the GB transmission system
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Annex C – Wholesale market
C.1
Overview of BETTA arrangements
This section provides further information on the British Electricity Trading and Transmission Arrangements (BETTA),
which commenced operation in 2005 in England, Wales and Scotland (extending the NETA arrangements that were
intrtoduced in England and Wales in 2001). Figure 23 presents an overview of the current electricity trading and
balancing arrangements in GB.
BETTA can be summarised by the following five elements:

forwards and futures markets, that allow contracts for electricity to be struck up to several years ahead;

short-term ‘spot’ power exchanges, enabling participants to ‘fine-tune’ their contracts up until Gate Closure
(currently one hour before delivery);

a common scheme for transmission access and charging;

a Balancing Mechanism (BM), which opens at Gate Closure, in which National Grid as System Operator (SO)
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.
Figure 23 – Great Britain electricity trading arrangements under BETTA
Sources: Ofgem and Pöyry Management Consulting.
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C.2
The Balancing and Settlement Code
The Balancing and settlement Code (BSC) defines the functionality of both the Balancing Mechanism and Imbalance
Settlement. BSC Parties (entities that have signed the BSC Framework Agreement and are thus bound by the code
thus giving the BSC contractual force) are the only entities allowed to partake in the balancing mechanism. Any entity
who wishes to physically trade power must be a Balancing and Settlement Code (BSC) party. All parties have two
energy accounts (production and consumption). BSC parties own one or more Balancing Mechanism Units (BMUs).
Most large generation units are an individual BMU with small generators often aggregated within a supplier’s BMU.
The following concepts are important:



Contracted position: Prior to gate closure, generators, suppliers and traders are free to buy and sell electricity.
BSC parties notify Elexon of their energy trades through Energy Contract Volume Notifications (ECVN). The
aggregate of these contracts represents the party’s contracted position for consumption and production of
electricity.
Physical notification: At gate closure, generators have scheduled their own plants and send Final Physical
Notifications (FPN’s) of their expected generation for each generation BMU to National Grid.
Metered volume: All metered volume data is submitted to Elexon. Metered volumes are aggregated to the BSC
party level (separately for production and consumption) for imbalance settlement.
At gate closure, offers to adjust levels of generation and demand are submitted into the Balancing Mechanism.
National Grid can accept these offers (amongst other options) to increase or decrease generation or demand and
balance the system in real-time. The volume traded in the Balancing Mechanism is on average 2% of the overall
generation.
BSC parties are penalised for imbalances between their contracted position and their metered volume. This is done
separately or their production and consumption accounts. They must pay the System Buy Price (SBP) for any shortfall
in metered volume and receive System Sell Price (SSP) for any metered volume above their contracted position. This
process is known as the ‘cash-out’ process.
C.2.1
The Balancing Mechanism
The Balancing Mechanism (BM) was designed as a tool to assist National Grid, as the SO, to keep the Transmission
System in balance in real time. The SO can adjust levels of generation and demand by accepting Bids and Offers
which have been submitted into the BM. Participants can (notionally) choose to submit into BM:


Offers to increase generation (or reduce demand); and
Bids to reduce generation (or increase demand)
The data submission required to submit Bids and Offers is illustrated in Figure 24. Accepted bids and offers are paidas-bid.
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Figure 24 – Data submission for participation in the Balancing Mechanism
Intended generation profile
Bid & Offer data
• (Final) Physical Notifications
• Maximum Export Limit (MEL)
• Maximum Import Limit (MIL)
• Up to three Run-Up Rate(s) and up to three RunDown Rate(s
• Notice to Deviate from Zero (NDZ)
• Notice to Deliver Offers (NTO)
• Notice to Deliver Bids (NTB),
• Minimum Zero Time (MZT),
• Minimum Non-Zero Time (MNZT)
• Stable Export Limit (SEL)
• Stable Import Limit (SIL)
• Maximum Delivery Volume
In respect of Interconnector BM Units:
• the value of Maximum Import Limit for the
Production BM Unit shall be zero; and
• the value of Maximum Export Limit for the
Consumption BM Unit shall be zero.
C.2.2
• Up to 5 offers and 5 bids
• Each has a volume associated with deviations from
FPN
• Pricing is ‘simple’ – only £/MWh
• Monotonically increasing in price
• Cancelling bids/offers must also be submitted
MW
Plant physical characteristics
12.00
12.30
Imbalance Settlement
The intention of electricity imbalance (or cashout) arrangements is to settle energy taken or produced without a
contract, whether through involuntary or deliberate actions. Imbalance volumes are defined as the difference between
actual physical volumes and contracted volumes, for each account. These volumes are settled at cashout prices
determined in accordance with rules specified in the Balancing and Settlement Code (BSC). Cashout prices are less
favourable than market prices in order to provide a financial incentive for parties to balance their own positions and, in
so doing, contribute to maintaining security of supply.
A dual price cashout system operates, with energy surpluses and energy deficits settled using different cashout prices:


System Sell Price (SSP), paid to Parties with surplus energy, and
System Buy Price (SBP), paid by Parties with a deficit of energy.
The cashout price applied to an imbalance position depends upon the direction of the imbalance on the system as a
whole:


imbalances in the same direction as the Transmission System are cashed out at the ‘main’ cashout price
calculated from National Grid’s balancing actions; and
imbalances in the opposite direction to the Transmission System are cashed out at the ‘reverse’ cashout price
based on power exchange trade prices (a market index).
An overview of the dual cashout price system is shown in Table 12. Note, these arrangements are undergoing review
as discussed in Section 6.2.4.
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Table 12 – Dual cashout price arrangements
Account imbalance
System imbalance
Short
Long
Short
pay @ SBP
paid @ SSP based on market index
Long
pay @ SBP based on market index
paid @ SSP
C.2.3
Incorporating a battery into the ‘Total System’ under the BSC
Every BM Unit (i.e. every piece of apparatus operating under the BSC) must either be registered as being under
Central Volume Allocation (CVA) or Supplier Volume Allocation (SVA).
C.2.3.1 CVA
Apparatus that is obliged to register with the CMRS (i.e. apparatus obliged to undertake CVA, see Section C.2.3) and
by definition obliged to be part of the BSC include the following:




plant or apparatus directly connected to the transmission system;
licensable generating plant;
interconnectors; or
other units, as determined by the Panel.
C.2.3.2 SVA
If the apparatus does not fall under the above categories, and if the owner chooses or is obliged to register the
apparatus under the BSC (i.e. as part of a BM Unit), they must do it under SVA arrangements. In this case no direct
interaction is required between the battery owner/operator and the BSC, rather, an agreement must be established with
a supplier who takes on all BSC responsibilities on behalf of the battery owner/operator.
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Annex D – Balancing Services
The major revenues available to providers of balancing services especially for non-BMUs are: STOR, Fast Reserve
and Frequency Response. The markets for these services are described in the following sections.
D.1
STOR
STOR is essentially capacity that National Grid retains on stand-by that can be called on to generate within four hours
of instruction. It is required for the following reasons:



Demand forecast errors: Most end users of electricity do not need to provide any statement of their intended
usage and so electricity demand is uncertain and actual demand is often quite different to forecast even quite
close to real time.
Unexpected loss of thermal generation: Large generator units are required to notify their intended output to
National Grid. However, problems can occur and unexpected trips can lead to a short notice requirement for
additional generation.
Variable wind generation: Output from wind capacity is inherently variable and unpredictable even close to real
time. Therefore reserve is required to deal with situations where wind generation is lower than expected.
Of these three basic reasons for the need for STOR, the last (variable wind generation) is the one which is set to
change most in the coming years.
The STOR service retains spare generation capacity on stand-by during certain hours of the day (typically periods
when demand is changing rapidly). There are two categories of STOR:


Committed providers must be available in all of the required availability windows in each season they are
contracted.
Flexible providers are not obliged to offer services in all availability windows and National Grid is not obliged to
accept the service when offered.
STOR is open to both BM participants (generally transmission connected generation from large power station sites)
and non-BM participants (generally small transmission or distribution connected generation and demand). However
BM participants can only be ‘committed’ providers of STOR generation.
National Grid procures STOR through a tender process, currently conducted three times a year. Availability is sought
during ‘reserve windows’ when National Grid’s requirements are highest – generally during periods of rapid change in
demand or generator loading, since this is when generator failure is most likely to occur. The key technical
requirements to be considered for the STOR service are:






47
ability to deliver at least 3MW of reserve ;
ability to react within 240 minutes of an instruction (though, since many STOR providers can respond much faster,
a premium is placed upon rapid delivery; and in its tender information National Grid highlight a benchmark of 20
minutes);
ability to deliver for a minimum of two hours;
have a recovery period after provision of reserve of less than 20 hours;
be able to provide reserve at least three times a week (though average utilisation will be much lower); and
operational metering.
Availability payments are made during contracted windows and utilisation payments are made whenever reserve is
delivered.
47
This can either be provided through generation or steady demand reduction
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D.2
Fast Reserve
Fast Reserve is used in addition to other energy balancing services, to control frequency changes that might arise from
sudden, and sometimes unpredictable, changes in generation or demand. Fast Reserve provides the rapid and
reliable delivery of active power through an increased output from generation or a reduction in consumption from
demand sources, following receipt of an electronic despatch instruction from National Grid. This service operates in
quicker timeframes than STOR and requires a 50MW minimum capacity.
National Grid offers two types of Fast reserve contract; these are an ‘Optional Service’ and a ‘Firm Service’.
Generators contracted under the ‘Optional Service’ enter into a framework agreement with National Grid and are paid
on the basis of an ‘Enhanced Rate Availability Fee’ (£/h) payment for periods of time where they provide National Grid
(following despatch) with MW run-up and run-down rates.
The ‘Firm Service’ is tendered on a monthly basis. This tender process allows participants to contract with National
Grid for a single months (e.g. just that tender month) or for multiple months. Providers under the firm service will
receive an Availability Fee (£/h) for each hour in a Tendered Service Period where the service is available and an
utilisation fee (£/MW/h) payable when energy is delivered.
The key technical requirements to be considered for the Fast Reserve service are:






D.3
have the delivery rate greater than or equal to 25MW / minute.
have the capability to delivery within 2 minutes of instruction.
be able to sustain output for minimum 15 minutes.
halt or start to unwind Fast Reserve delivery within 2 minutes of instruction.
have the unwind rate greater than or equal to 25MW / minute.
deliver a minimum 50MW for a single instructable unit or aggregation of more than one unit.
Frequency response
Frequency Response is the automatic provision of increased generation or demand reduction in response to a drop in
system frequency. It is a service that maintains the system frequency at 50Hz, and restores the frequency to 50Hz in
the event of an outage or change in demand, by generators increasing or decreasing their output on a second-bysecond basis. The service is paid for by National Grid as the system operator.
Commercial Frequency Response is a collection of services that can be provided by demand side participants and
generation plant. The technical characteristics of these services are different to those required under mandatory
service arrangements, and range from enhanced mandatory dynamic services through to non-dynamic services
affected via LF relays. The costs and volumes include services provided by demand side participants through
Frequency Control Demand Management (FCDM) and through the firm frequency response (FFR) tender rounds.
Firm Frequency Response (FFR) is the firm provision of Dynamic or Non-Dynamic Response to changes in Frequency.
Unlike Mandatory Frequency response (which is only open to Balancing Mechanism Units) FFR is also available to
non-BMU providers. National Grid procures the services through a competitive tender process, where tenders can bid
for low frequency events, high frequency events or both. National Grid will accept the most economical tenders. A
successful tender then becomes contractually binding.
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Annex E – Capacity market
E.1
Introduction
The Electricity Market Reform (EMR) proposals have now been several years in the making. Key steps in the process
to date include a White Paper in July 2011, a draft Energy Bill in May 2012 and Royal Assent for the Energy Bill 2013
in December 2013.
The government’s objectives, as stated in the draft Delivery Plan, for EMR are to:



Ensure a secure electricity supply by incentivising a diverse range of energy sources, including renewables,
nuclear, CCS equipped plant, unabated gas and demand side approaches; this will ensure we have sufficient
reliable capacity to minimise the risk of supply shortages.
Ensure sufficient investment in sustainable low-carbon technologies to put us on a path consistent with our
EU 2020 renewables target and our longer term target to reduce carbon emissions by at least 80% of 1990 levels
by 2050.
Maximise benefits and minimise costs to taxpayers and consumers to the economy as a whole and to
taxpayers and consumers – maintaining affordable electricity bills while delivering the investment needed.
The key elements of the EMR package are Feed in Tariffs with Contract for Difference (FiT CfDs) to support
investment in low carbon generation and a Capacity Market to support security of supply. These mechanisms are
supported by an Emissions Performance Standard (EPS) and a Carbon Price Support mechanism, which has already
been implemented under a separate process. Figure 25 summarises the separate elements of the EMR package.
Figure 25 – Overview of Electricity Market Reform
The government states that the reform of the electricity market is in response to the following challenges:



Security of supply is threatened as existing plant closes.
There is a need to decarbonise electricity generation. The government suggests that carbon prices are volatile
and hard to predict. It also states that the social cost of carbon is not fully reflected in the electricity price.
Electricity demand is likely to rise and overall demand for electricity may double by 2050.
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
Electricity prices are expected to rise. However, the government believes EMR can mitigate price increases and
suggests that the net benefits of EMR are £9billion compared to a business as usual scenario to 2030.
E.2
Capacity Market
The introduction of a Capacity Market is a key component of the government’s EMR proposals. With significant
amounts of capacity due to close in the next decade, and the expected increase in intermittent generation by 2020
potentially reducing the operating hours of mid-merit plant, its introduction is intended to ensure that there are sufficient
incentives on capacity providers in order to maintain an adequate security of supply.
The aim of the Capacity Market is to deliver generation adequacy. It offers capacity providers a capacity payment
revenue stream, in return for which they commit to deliver energy in periods of system stress or face exposure to
penalties if they fail to deliver.
Capacity contracts will be allocated to providers through auctions intended to secure a capacity requirement needed to
meet a 3-hour loss of load expectation reliability standard. The auction clearing price forms the basis of the capacity
payment to successful auction participants. The first auction is expected to run in 2014 for delivery of capacity from 1
October 2018 to 30 September 2019, subject to State Aid clearance. In addition, auctions will be held one year ahead
of delivery for demand side response (including embedded generation and smaller storage), with the first auction taking
place in 2015, for delivery in 2016/17.
Further details on selected aspects of the proposed design are set out below, based on the capacity market proposals
48
specified in October 2013 .
E.2.1
Eligibility
The Capacity Market is intended to be technology neutral across generation, storage and demand side providers and
to allow new entrants and existing capacity to participate. However, there are some limitations on participation.
Interconnection and interconnected capacity are not eligible within the current design. Low carbon capacity sources
receiving support payments via the Renewables Obligation, Contract for Difference Feed-in Tariffs (CfD FiTs) and
small scale (<5MW) FiTs are also ineligible, at least while they are in receipt of administratively determined payments,
to avoid potential double payment. Small scale (<2MW) capacity is not eligible unless combined with other capacity
through an aggregation service.
E.2.2
Capacity requirement
The amount of capacity to be secured will be determined with reference to an enduring reliability standard set by the
Secretary of State, which is to be a 3 hour loss of load expectation (LOLE). Once defined, the System Operator (as
Capacity Market administrator) will identify a target capacity quantity required to meet the reliability standard. The
contribution of ineligible capacity, providers of balancing services and plants that opt out of the Capacity Market will be
‘netted off’ when setting the total amount of capacity required.
Based on the target capacity requirement, an administered demand curve will be constructed, using a methodology to
be defined by the Secretary of State. The demand curve defines how much de-rated capacity will be contracted given
any potential capacity price at the auction. The administered demand curve will be constructed around several key
points outlined below:

48
Target capacity: the price for capacity required to meet the identified target capacity level will be set with
reference to the net cost of new entry (net CONE). The net CONE will be based upon the cost of a new build
OCGT plant minus expected revenue from the electricity market. A value of £29/kW is proposed for net CONE.
https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/249565/capacity_market_rules_consultation_draft.pdf
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

49
Minimum capacity: a minimum capacity requirement will be set potentially 1.5GW below the target at a price
cap defined either as a fixed price, currently proposed to be £75/kW.
Maximum capacity: a maximum capacity requirement will be set at potentially 1.5GW above the target, with the
price dropping towards, and potentially reaching, zero.
E.2.3
Auction
Capacity requirements for each delivery year will be secured through a 4 year-ahead auction, supplemented by a
further 1 year-ahead auction to allow demand side and storage participation and fine tuning.
Each auction will operate on a pay-as-clear basis, with all successful bidders receiving the clearing price. A
‘descending clock’ format will be adopted, under which bidders indicate the quantity of capacity that they are prepared
to offer at an announced price, starting at the price cap in the first round. Bidders indicate an ‘exit price’, which is the
minimum price at which they are prepared to offer capacity. When the announced price falls below a bidder’s exit
price, its capacity is removed. In subsequent rounds, the price is progressively lowered until supply intersects the
administered demand curve and the auction clears. The clearing price in each auction is set based on the exit price of
the cheapest unit that is not contracted.
There are variations in bidding options and the capacity contracts on offer depending upon whether the capacity is
existing, refurbished or new. Existing capacity providers can secure 1 year capacity agreements through the auctions.
During the bidding process, they can choose to act as a ‘Price Maker’ or a ‘Price Taker’, with the latter the default
position for existing capacity. Price Takers must submit an exit price at or below a defined Price Taker Threshold (PT
Threshold), which may be set at 50% of net CONE or 70% of the last clearing price set by a new entrant. Price takers
cannot exit the auction until the price drops below the PT Threshold. Existing capacity can select Price Maker status,
but must then formally justify bids in excess of the PT Threshold.
New and refurbished plants are classed as Price Makers, having freedom to select their own bid price within the
auction without the need for justification. They also have the ability to select longer term capacity contracts (up to 15
years is available for new plant and up to 3 years for refurbished plant) to support an investment case. In longer term
agreements, the capacity payment set by the auction clearing price is adjusted for inflation on an annual basis for the
contract duration.
E.2.4
Penalty arrangements
Capacity agreements require their holders to deliver energy in line with the underlying capacity obligation in system
stress periods. Failure to deliver will result in a penalty.
System stress events are defined as any settlement periods in which either voltage control or controlled load shedding
are experienced for a period of 15 minutes or longer. To allow market participants to manage the risk of exposure to
penalties, the System Operator will issue a Capacity Market Warning (CMW) at least 4 hours ahead of an anticipated
system stress event. This is intended to give capacity providers 4 hours in which to respond. Contracted providers not
delivering in line with their obligations 4 hours following a CMW will be liable to financial penalties. If a stress event
occurs unexpectedly without the provision of a CMW or before the 4 hour window has elapsed, no penalties will apply
for the relevant periods.
E.2.5
Exit
DECC outlines that it expects the Capacity Market to be required for at least 10 years, once implemented. However, it
outlines its intention to review the need for a Capacity Market every five years, highlighting that it may be right to exit
the Capacity Market in future if the underlying electricity market develops sufficiently (particularly through
improvements in market liquidity, an active demand side and more interconnection).
49
1.5GW has been proposed as it is equivalent to the de-rated capacity of two large CCGTs.
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