Memorandum submitted by the Sussex Energy
Group
ABOUT THE
SUSSEX ENERGY
GROUP
1. The Sussex Energy Group undertakes academically
rigorous, inter-disciplinary research that engages with policy-makers
and practitioners. The aim of our research is to identify ways
of achieving the transition to sustainable, low carbon energy
systems whilst addressing other important policy objectives such
as energy security. We a group of 15 social scientists, working
from a multidisciplinary perspective. Our core support is provided
by the Economic and Social Research Council, and we also have
funding from a diverse array of other sources. Through the Group,
the University of Sussex is a core partner of the Tyndall Centre
for Climate Change Research. The Group is also part of the UK
Energy Research Centre.
2. We welcome this inquiry into the future of
Britain's electricity networks. Networks are often forgotten in
debates about energy futures, yet they will play a crucial role
in facilitating the transition to a sustainable, low carbon energy
system. In our response to the Committee's questions, we have
spent most of the time on those questions in which we have particular
expertise. This expertise derives from a number of related Sussex
Energy Group projects and activities. These include research on
the governance and regulation of electricity networks in the UK
and Denmark, the role of control systems in these networks, and
on the policy implications of decentralised energy systems.
SPECIFIC RESPONSES
TO THE
COMMITTEE'S
QUESTIONS
What should the Government's vision be for Britain's
electricity networks, if it is to meet the EU 2020 renewables
target, and longer-term security of energy supply and climate
change goals?
3. The EU 2020 target will mean a significant
increase in the deployment of renewable energy in the UK. Renewable
electricity production will play a particularly prominent role
in meeting the UK's target under the EU burden-sharing agreement.
This expansion of renewable electricity—together with other
changes required to reduce carbon emissions—will require
electricity networks to be extended to new locations, and to operate
in new ways. The planned expansion of offshore wind power will
increase the amount of intermittent power generation in the electricity
system and will also require a new offshore network infrastructure
to be built. The growing deployment of other renewable technologies
and combined heat and power (CHP) is likely to entail a shift
in the scale of electricity generation. Electricity distribution
networks will therefore be required to integrate generation at
a range of scales—from an individual household solar panel
to an inner-city CHP plant. Distribution system operators will
need to play a more active role in system operation and control.
4. What will need to change is not just the layout
of cables, but rather the overall system infrastructure that connects
generation and supply, including for example new control systems
infrastructure that can integrate demand into system operation.
This transformation will not just be a technical challenge. The
government's vision also needs to have economic, institutional
and regulatory components. History shows that technologies, institutions
and policies change in inter-related ways. In the UK, these changes
have built an increasingly centralised electricity system which
is built around fossil and nuclear generation. The "lock-in"
of this system to a centralised model presents a challenge when
government policies now require the system to change.[117]
5. Overcoming this lock-in therefore requires
regulatory and policy changes which support the required changes
in technologies. This has consequences for the approach to economic
analysis and regulation that is followed by government and the
regulator. In the past, UK regulation has approached potential
changes in electricity networks in a piecemeal fashion. Potential
new investments have been assessed to see whether they improve
the efficiency of the electricity network we currently have. But
the need to change to a significantly different network architecture
means that such an approach is no longer fit for purpose. Economic
appraisal will need to take account of the electricity networks
that will be required in the future—and use these future
systems as a benchmark against which new investments are appraised.
How do we ensure the regulatory framework is flexible
enough to cope with uncertainty over the future generation mix?
6. There are two challenges to consider:
to build a network infrastructure that is flexible enough to accommodate
various development options for both generation and demand (which
clearly come at a cost), and to have a regulatory framework that
allows for this infrastructure flexibility and is itself flexible
enough to adapt to new developments.
7. The current UK system of incentive regulation
of networks is a relative flexible regime, with fixed regulatory
periods, regular reviews and in-built learning processes. However,
this regulatory framework was developed to increase the efficiency
of the existing network, and minimise costs to consumers. Long-term
transformation of these networks in the way that is now necessary
is more difficult to achieve within this regulatory framework.
As the discussion surrounding the recent Transmission Access Review[118]
has demonstrated, regulators now need to allow investment that
is more strategic—and to take a view of the way in which
medium and long-term targets for renewables might be achieved.
8. Therefore, in order to promote a long-term
transformation of the network, incentives that mimic market forces
need to be complemented by instruments that: (i) go beyond one
five-year regulatory period; (ii) link regulatory interventions
to scenarios of future development options; and (iii) provide
coordination mechanisms for the stakeholders involved. Some progress
has been made by Ofgem to fulfil these requirements. For example,
the recently completed Long Term Electricity Network Scenarios
(LENS) project sets out a range of scenarios for the future of
electricity grids.[119]
The Transmission Access Review has proposed some new incentives
for investment "ahead of need" to connect generation
assets such as offshore windfarms. However, progress in implementing
new incentives has often been slow. Therefore, questions remain
about the extent to which these changes are occurring fast enough
to deliver the UK's 15% renewable energy target.
What are the technical, commercial and regulatory
barriers that need to be overcome to ensure sufficient network
capacity is in place to connect a large increase in onshore renewables,
particularly wind power, as well as new nuclear build in the future?
For example issues may include the use of locational pricing,
or the availability of skills.
9. A number of barriers are slowing down
the connection and integration of wind energy within the UK electricity
network. For example, there is a particularly large queue of wind
power plants waiting for connection in Scotland. Both cost and
planning barriers to network investments have contributed to this
slow progress.
10. For offshore wind, the barriers are largely
due to the incumbent regulatory regime. This regime gives transmission
companies little incentive to invest strategically in offshore
infrastructure. Such strategic investment may be required before
there are firm plans to build specific offshore wind farms that
will full use the resulting transmission capacity. Whilst this
brings with it risks of over-investment and stranded assets, the
work of the Energy Networks Strategy Group shows some network
investments are fairly robust to different scenarios of renewables
deployment in the UK.[120]
So the risks of implementing these "ahead of need" are
relatively low.
11. According to one recent assessment,
other regulatory barriers include the inability of the incumbent
regime to differentiate between different types of generation,
to recognise the `replacement' role of renewable generation, or
to allow transmission capacity to be shared between renewable
and non-renewable generation.[121]
The process of developing modifications to this regime has been
slow. It is already over six years since the former DTI published
its strategy for offshore wind: Future Offshore.[122]
Whilst the need for new incentives for offshore transmission investment
was acknowledged in this strategy, implementation of these incentives
has not yet been completed.
12. As a result of the Transmission Access
Review, some options for a new regulatory approach have been put
forward. These include both short term fix to speed up the connection
process and overcome the immediate barriers to progress. A range
of long-term options have also been proposed. Whilst all have
pros and cons, some of the more market-based options are highly
complex. Although they are designed to maximise economic efficiency,
there are concerns that these arrangements for transmission investment
and access will be expensive and time consuming to implement.
What challenges will higher levels of embedded
and distributed generation create for Britain's electricity networks?
13. There are a number of technical, economic
and regulatory and political challenges associated with higher
levels of distributed generation in the UK. One of the key reasons
why such generation is seen as "difficult" the UK context
is that the incumbent system is highly centralised. Unlike many
other European countries, the UK has no recent tradition of decentralised
electricity production. It is also important to note that distributed
electricity generation (and other distributed energy options)
can be deployed at a range of scales. Distributed generation can
include household technologies such as micro-CHP or solar PV panels,
small-scale wind farm in a village or a city-wide CHP system.
Implementation of these options could include a variety of different
investors from householders and energy companies to local authorities.
But significant policy changes are required to enable this full
range of actors and options to play a significant role.
14. The technical challenges arise because distributed
generation has a particularly strong impact on the existing distribution
network. In the UK, this network was not designed for that purpose.
Furthermore, distributed generation is not just about connecting
new plants to the existing system, but also about innovation and
transformation of the system so that such plants can be properly
integrated into system operation. The associated regulatory challenges
arise because a more decentralised electricity system requires
distribution network operators to take on a more active role in
managing their networks—and therefore need the appropriate
incentives to do so. The impact of distributed generation on distribution
networks can vary widely and depends, for example, on the density
and number of distributed generators on the system, the extent
to which networks are urban or rural, and the types of distributed
generators that are connected. These factors and others should
be taken into account by the regulatory framework, especially
when comparing the efficiency of network operators.
15. The technical and regulatory impacts
of distributed generation are explored further in the Table below.
This shows how both sets of impacts will vary according to the
approach taken to distributed generation. This approach ranges
from piecemeal connection (in the left hand column) to transformation
(in the right had column). In the former case, each generator
is appraised with reference to the current system and is connected
as a "one off". In the latter case, there is a strategic
and co-ordinated approach to developing generation and network
infrastructure together with demand-side measures. The result
is a network that is very different to the one we have today.
At present, the UK regulatory regime is making some tentative
moves from connection to integration. It has a long way to go
before it is capable of facilitating the innovation and system
transformation that would be required to absorb significant amounts
of distributed generation.
Table: From the connection of distributed
generation (DG) to system transformation
| Connection | Integration
| Innovation | Transformation
|
| Technical issues | Connection of DG to distribution network
DG contributes energy to system
| Integration of DG into operation of existing network
DG takes some responsibility for system support
DG contributes capacity to system
| See Integration;
Development and deployment of innovative network technologies to integrate DG into network operation
| Transformation of network structure beyond innovation in individual parts of the network. Changes in overall system design and control
|
| Economic and Regulatory Issues | DG connection means additional network costs
| Additional network costs of DG can be reduced;
In some cases, DG can help reduce network costs
| See Integration;
Additional costs and benefits of RD&D
| Difficult to apply "traditional" cost-benefit analysis to system transformation
|
| |
| | |
What are the estimated costs of upgrading our electricity networks,
and how will these be met?
16. We have not developed our own estimates of the costs
of upgrading electricity networks to facilitate the 2020 renewables
target and other measures required to meet medium- and long-term
emissions reduction targets. The government-led Electricity Networks
Strategy Group recently published a cost estimate of £4.7
billion.[123] They
argue that this expenditure would be required to meet the 2020
renewables target as well as to connect other generation investment
it regarded as "essential" such as some new nuclear.
As the ENSG acknowledge, the actual costs will depend on how the
renewables target is met and a range of other factors.
17. Looking further ahead, the costs of network investment
to help facilitate the deep cuts in emissions required by 2050
are much more difficult to estimate. In principle, there are many
possible ways to achieve such deep cuts which could have significantly
different implications for networks. For example, a scenario in
which the electricity system is extended to meet demand for heating
and transport is likely to entail significantly higher network
costs than a scenario in which transport and heating are met by
other low carbon energy sources or carriers (eg hydrogen, renewable
heat and so on). A set of scenarios for 2050 were recently developed
for Ofgem which usefully illustrate a wide range of possible development
pathways for UK electricity networks.[124]
An economic analysis of these scenarios was carried out, albeit
with the usual caveats about the difficulty of assessing costs
over such long timescales.
18. Whatever future pathway emerges for UK electricity networks,
a key principle is that the majority of the costs should be shared
across all consumers. There are two reasons for this. First, network
assets are natural monopolies. Second, the need to upgrade and
extend these network assets is driven by public policy objectives
such as the 2020 renewables target. It is unlikely that new infrastructure
to meet these objectives could be financed solely through transmission
access payments by new generators. Similarly, it is difficult
to justify passing on the costs of these network upgrades to consumers
who happen to be connected near to the new generation assets.
How can the regulatory framework ensure adequate network investment
in light of the current credit crunch and recession?
19. Many have argued that one of the responses to the
credit crunch and recession should be public investment via green
stimulus packages (a "Green New Deal").[125]
These packages should comprise investment in a range of cleaner
technologies, infrastructures and industries—and therefore
represent an opportunity to increase investments in new, more
innovative electricity network infrastructure. Accelerating electricity
network investments through green stimulus packages could help
to counter any negative impacts of the recession on investment
plans. It would also have the advantage of tempering the regressive
increases in consumer electricity bills that would otherwise be
required.
How can the regulatory framework encourage network operators
to innovate, and what is the potential of smart grid technologies?
20. So far, the regulatory framework for electricity networks
has not been particularly successful at encouraging innovation.
The UK's price-based approach to regulation allows network companies
to increase their charges by the retail price index minus an efficiency
factor—a formula known as RPI-X. Whilst it has been argued
in the past that this should act as a driver of innovation, it
only does so if the aim of this innovation is to increase the
efficiency of current network operation. As a result, innovation
which would facilitate significant changes to the architecture
and operation of networks has not been encouraged.
21. In principle, the basic mechanisms of price-based regulation
can be modified to promote innovation by including incentives
for network operators to invest in research, development and demonstration
(R,D&D). Mechanisms such as the Innovation Funding Incentive
(IFI) and Registered Power Zones (RPZs) which were introduced
in the UK a few years ago are designed to achieve this. These
mechanisms were designed to allow distribution network companies
to recover some of the costs of R,D&D investment from their
customer base. However, these schemes have only had limited success.[126]
The reason for this poor outcome is that the innovative capacity
within network companies started from a very low base. Furthermore,
the incentives from RPZ and IFI were tightly drawn and were not
strong enough in many cases. If they are to succeed in future,
these instruments need to be more long-term, they should include
generators (not just network companies), and they should encourage
cooperation between market participants.
22. Smart grid concepts, as pursued for example by the
European Technology Platform on SmartGrids, covers a broad of
technologies including network technologies, control systems,
generation technologies, smart meters and storage. An electricity
system with a higher share of intermittent and distributed generation
will inevitably require an increasing level of operational flexibility
on the generation side, including small-scale plants. It will
also require consumers to adapt to these generation patterns to
some extent—either actively (eg by changing their usage
patterns) or passively (eg by allowing some appliances to be switched
on and off remotely by their electricity supplier). Smart grids
can help reduce the additional system costs a changing generation
pattern entails and can increase the level of intermittent and
distributed generation the system can absorb.
23. This vision of smart grids is a broad one, and involves
considering how a transformation can be achieved within the overall
electricity system. With this in mind, it is clear that the regulatory
approach to network innovation in the UK is far from adequate.
Other measures are required to encourage much more ambitious levels
of innovation and the deployment of smarter grids as and when
they are required. Direct funding for R,D&D outside the incentive
regulation framework will be needed to complement the recent increases
in public R,D&D funding for individual low carbon technologies.
For example, public funding could help to support a series of
smart grid experiments which include a variety of decentralised
energy sources and new grid technologies. Some of these might
integrate charging stations for electric vehicles or sophisticated
control systems that are designed to turn domestic appliances
on and off to help balance the system. Such experiments would
facilitate learning about what works, and would help to inform
future policies designed to implement smart grids more widely.
24. A final important observation on this question is
that the current electricity system can accommodate a higher share
of new generators and innovative technologies than it does at
the moment. Although smart grid technologies will become important
to increase the share of intermittent and distributed generation
in future, their promise should not distract attention from what
can be done already without them.
Is there sufficient investment in R&D and innovation for
transmission and distribution technologies?
25. There is clear evidence that electricity market liberalisation
in general and RPI-X price-based regulation in particular have
led to a significant decline in R&D and innovation. While
it is difficult to judge what counts as a sufficient level of
R&D and innovation, this trend needs to be reversed to provide
the necessary electricity network technologies to support a rapid
expansion of renewables. In principle, there can be an R&D
level that is too high and inefficient. However, given the potential
and demand for innovations in the electricity system, it can be
argued that the regulatory framework should err on the side of
innovation, which may partly happen at the expense of efficiency
in the short-term. As stated above, a key priority within this
should be to fund the demonstration of new electricity system
concepts which combine new network technologies with those for
generation, demand management and so on.
What can the UK learn from the experience of other countries'
management of their electricity networks?
26. In terms of developing and adapting the incentive regulation
framework for electricity networks to new objectives, the UK has
gone much further than many other countries. However, this leadership
in developing and adapting the RPI-X framework does not mean that
the UK cannot learn from the different approaches followed by
other countries. In some cases, other countries have developed
more effective ways of managing their networks in new and innovative
ways.
27. A prominent example is Denmark, a country that is very
advanced in the deployment of distributed generation (DG) sources
and network development. Incentive regulation only plays a minor
role in this process. For example, a key instrument in Denmark
to deal with the costs of connecting distributed renewable energy
and combined heat and power (CHP) plants has been a mechanism
to share the network costs. These network costs are not borne
by the individual network company that connects DG to its network,
but companies get reimbursed for these costs and the costs are
then distributed among all consumers via the network companies.
Distributed generation is not seen as a property of an individual
distribution network, but rather as a property of the system as
a whole, driven by national policy targets. From this point of
view it would seem inappropriate to preserve or increase the efficiency
of an individual network by not connecting DG to that specific
network. Socialisation of network costs goes a long way to explain
why—unlike in the UK—the network costs of DG have
not been a major issue in Denmark.
28. Another example of a mechanism outside the incentive
regulation framework, is the governance of network R&D in
Denmark. Within the regulation of network tariffs in Denmark,
there are no regulatory instruments that are specifically geared
towards promoting innovation. However, there is a separate funding
mechanism for R&D based on a public service obligation. Through
a fund generated by this obligation, the system operator (energinet.dk)
can run strategic RD&D projects on a system level, together
with the distribution companies. One example is the cell projects
that aim to decentralise network control to individual parts of
the electricity network. Another is the more pervasive Ecogrid
project which aims to develop ways to increase the deployment
of renewable energy in Denmark without entailing a knock-on increase
in Denmark's reliance on neighbouring countries' electricity systems
to balance variations in supply and demand.
29. The need to initiate pilot projects to explore future
system architectures has also been recognised in Germany, where
the eEnergy programme has just been launched by the government.[127]
This provides direct funding to companies for smart grid pilot
projects where individual technologies are combined to test new
system solutions.
30. A final important lesson should be learned from other
countries such as Denmark, Spain or Germany with higher shares
of renewables and CHP in their electricity systems. Their experience
shows that while networks are important, it is at least as important
to provide an effective overall framework of economic incentives
for these types of generation to be built in the first place.
Getting the right incentives for electricity network development
to facilitate this is only part of the story.
March 2009
117
Foresight (2008). Powering Our Lives: Sustainable Energy Management
and the Built Environment. London, Government Office for Science. Back
118
Ofgem (2008). Transmission Access Review: Final Report. London,
Ofgem. Back
119
Ault, G, D Frame, et al. (2008). Electricity Network Scenarios
for Great Britain in 2050. Final Report for Ofgem's LENS Project.
London, Ofgem. Back
120
Electricity Networks Strategy Group (2009). Our Electricity Transmission
Network: A Vision for 2020. London, ENSG. Back
121
Baker, P (2008). Developing a transmission access regime to deliver
the UK's renewable targets. BIEE Academic Conference, Oxford.
September. Back
122
Department of Trade and Industry (2002). Future Offshore. London,
DTI. Back
123
Electricity Networks Strategy Group (2009). Our Electricity Transmission
Network: A Vision for 2020. London, ENSG. Back
124
Ault, G, D Frame, et al. (2008). Electricity Network Scenarios
for Great Britain in 2050. Final Report for Ofgem's LENS Project.
London, Ofgem. Back
125
See for example, Bowen, A, S Fankhauser, et al.
(2009). An outline of the case for a "green" stimulus.
London, LSE. Back
126
See for example, Woodman, B and P Baker (2008). Regulatory
Frameworks for Decentralised Energy. Energy Policy 36(12): 4527-4531. Back
127
See www.e-energie.info. Back
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