4 Making distribution smarter |
133. Massive investment in Britain's distribution
networks took place in the 1950s and 1960s, and now, as with the
transmission system, many of these assets are coming to the end
of their natural life. The need for renewal provides an opportunity
to 'future proof' the networks, allowing flexibility to incorporate
In this Chapter we look at the changing role of the distribution
networks; the importance of investment and innovation for developing
a smart grid; and the current means by which distribution network
operators (DNOs) recoup their costs.
The changing role of distribution
134. Britain's 14 distribution networks deliver
electricity from the transmission system to consumers via successive
stages of transformation from higher to lower voltage systems.
Power flows in one direction and is fairly predictable in terms
of daily and seasonal demand fluctuations. This traditional approach
could face a major shake-up with the development of more active
management of the networks by the DNOs. As a chief executive of
one of the companies told us: "[
] the role of the distribution
network will be very different in five, 10, 15 or 20 years' time".
In this section we consider the various developments in electricity
generation and consumption that will facilitate the creation of
a smart grid that involves active demand-side participation, and
some of the technical and regulatory challenges which must be
GREATER DISTRIBUTED GENERATION
135. Since the introduction of the Renewables
Obligation (RO) in 2002 there has been a steady increase in the
number of renewables projects, mainly wind farms, connecting at
the distribution level, either because they are too small or not
close enough to connect to the transmission system. This is known
as distributed or embedded generation. The Government's target
for 15% renewable energy by 2020 may lead to an increase in the
amount of new distributed generation coming on-stream in the next
decade. In addition, from 2010 feed-in tariffs will provide financial
support for new small-scale low-carbon electricity generation
up to 5 MW. The Department hopes this will encourage households,
communities and organisations, such as schools, hospitals, universities
and businesses to consider installing renewable technologies,
such as wind turbines, combined heat and power systems or solar
This smaller type of generating capacity is usually referred to
136. The distribution networks are able to manage
easily the level of generating capacity currently connecting to
their systems. The Minister told us up to 3.5 GW of microgeneration
could be absorbed without the need for network reinforcement.
There is also substantial headroom for larger forms of distributed
generation, depending on its size and location.
Moreover, financing and planning consent are currently the main
barriers to new distributed generation.
It is not yet clear what impact the new feed-in tariffs will have.
The Institution of Engineering and Technology told us, however,
that as the level of capacity grows beyond a certain point, the
cost of connecting it would increase significantly. Investment
in the distribution networks is, therefore, important to create
more flexibility before the system reaches this 'knee point'.
CHANGES IN DEMAND
137. In addition to changes in the supply of
electricity at a local and household level, the next decade will
see developments in how consumers use energy. One area will be
the take-up of electric vehicles. Though still at an embryonic
stage, the electrification of the transport sector could be a
key part of a future decarbonised energy system. Space heating
too could largely be provided by electricity. The resulting changes
to the demand profile of households and businesses will present
new challenges to the design and operation of the distribution
networks. The heating and transport sectors will also have the
potential to provide a significant energy storage capacity that
has, hitherto, not existed. We examined in Chapter 2 the role
this could play in coping with the intermittency of wind generation,
thus allowing a greater level of distributed generation to connect
to the networks than would otherwise be the case.
138. Further changes on the demand side should
arise from the national roll-out of smart meters to all households
over the next decade. They will provide real-time information
to consumers about their energy usage, which will be relayed automatically
to electricity suppliers. The Government believes smart metering
will make households more aware of how they use energy, hopefully
resulting in behavioural changes that reduce their consumption.
Smart meters could also allow companies to offer more sophisticated
pricing tariffs that enable customers to manage their demand so
they consume more during periods when the system is less constrained.
Looking further ahead, it is envisaged that energy companies could
control remotely household appliances, determining the operation
of washing machines, dish washers and immersion heaters overnight,
for example, according to the availability of supply. The charging
of electric vehicles could also be managed in the same way. Hence,
smart meters are seen as a vital enabling technology for the creation
of a smart grid.
TECHNICAL AND REGULATORY CHALLENGES
139. Smart metering and financial incentives
for household and community renewables provide the means for people
to become more engaged with their energy consumption, and their
potential role in reducing carbon emissions.
Although, as one witness noted, consumers "[
always be more interested in soap operas than in exactly how the
power system is being balanced".
Therefore, if DNOs are to manage greater levels of distributed
generation, and make best use of the flexibility provided by the
remote operation of appliances and vehicle charging, they will
have to play a more active role in managing electricity demand
and supply across their networks.
At the same time, a large expansion in the level of distributed
generation could in the future give rise to situations where the
distribution system exports electricity back into the high voltage
transmission network. This will require an additional role for
the DNO in managing power flows at the interface of the distribution
and transmission networks. Whereas at present there is only one
system operator, National Grid, which balances demand and supply
across the entire system, it is possible to envisage a situation
where the DNO may become a system operator as well.
The Minister told us that at present this issue was "an open
140. Creating a smart grid poses regulatory challenges.
For example, the introduction of EU electro-technical standards
for household appliances will provide the necessary functionality
for the development of 'smart demand'.
Elsewhere, DNOs will need the appropriate incentives to encourage
them to take a more active role in managing their networks. Dr
Jim Watson told us: "the rules and regulations we have are
designed for the incumbent system and they have served us well,
but they will probably have to change fairly radically [
Phil Baker and Dr Bridget Woodman of the University of Exeter
noted: "there are few incentives for DNOs to invest in technologies,
which would allow their networks to be more actively managed".
Prof Goran Strbac noted, for example, that electricity sold on
the wholesale market can more than double in cost by the time
it reaches consumers, reflecting the cost of transmission and
distribution services to transport the electricity from the generator
to the customer. In contrast, distributed generation that is located
near to the source of demand may circumvent these costs and, therefore,
have a higher value than conventional generation. However, these
potential benefits are not fully recognised within the regulatory
framework. Prof Strbac told us: "Realising the value of distributed
generation and responsive demand [
] requires the creation
of a level playing field".
This means fair treatment in terms of network access and charging
for both generation and demand, and within the BETTA market.
141. There are also technical challenges involved
in the delivery of a smart grid. The distribution networks were
not designed to accommodate large volumes of small and medium-scale
generation. Potential difficulties include: accommodating bi-directional
power flows; maintaining electricity flows at a level that is
consistent with equipment ratings; ensuring voltage variations
remain within safe and statutory limits; and ensuring power flows
from local generation do not create short-circuit currents in
the event of network faults.
Several witnesses told us many of these issues are already well-understood
by engineers, though there is a lack of experience to date in
applying the solutions in a smart grid context.
We discuss the available incentives to adopt new technologies
later in this Chapter.
142. For DNOs to take on a system operator role
will also require the installation of sophisticated information,
communication and control technologies to monitor and control
the electricity system.
These will be needed to manage, for example, the potential unpredictability
of greater levels of embedded generation. The ability for all
parts of the system to communicate with one another will be a
vital component of smart grids. This will require a highly capable
communications platform, able to meet a demanding set of requirements,
including coverage, reliability, responsiveness and security.
143. There are various technologies available
in Britain that the communications regulator, Ofcom, is considering
as options for providing smart grid services, including the 3G
mobile network and fixed line broadband. However, countries such
as the US that have already begun to deploy smart grid technologies
have eschewed these solutions because they either do not provide
reliable coverage or operate at sufficiently low cost. Instead,
they have opted for a 'wireless mesh' approach. This is a communications
network made up of radio nodes, which allows appliances and smart
meters to speak to one other. The technology works best on sub-1 GHz
spectrum because the radio waves can travel further and penetrate
deeper. However, there is a lack of suitable spectrum currently
available in the UK, which is preventing companies wishing to
deploy the 'wireless mesh' approach from entering the market here.
Ofcom is currently consulting on the future use of the 872-876
MHz and 917-921 MHz frequency bands, which could be ideally suited
for smart grid use.
One of the companies keen to develop 'wireless mesh' technology
told the regulator that allocating this spectrum for the smart
grid would "enable the rapid deployment of cost-effective,
standards-based communications technology that will place the
UK among the worldwide leaders in smart grid deployment".
144. In the future there could
be potentially thousands of generators connected to the distribution
networks at scales varying from domestic solar panels to large
wind farms. Energy demand could also evolve and increase through
the electrification of the transport and heating sectors. The
deployment of smart grid technologies, such as smart meters, will
therefore be crucial to the effective and economically efficient
management of an increasingly complex energy system. This necessitates
a fundamental rethink of the role of distribution companies who
in the future will need to play a more active role in balancing
demand and supply across their networks, potentially taking on
a local system operator role.
145. Creating smarter distribution
poses significant challenges. Although many of the technical aspects
are well-understood there is relatively little experience of their
application to the smart grid. Furthermore, the regulatory framework
does not at present provide a level playing field for the adoption
of smart grid solutions, such as active demand management. Ofgem
must address these issues in the coming years. One area in which
we believe it could make an immediate difference is to work with
Ofcom to ensure the allocation of suitable spectrum for smart
grid use as soon as possible, thus enabling the full range of
smart grid technologies to be considered for deployment in Britain.
146. The DNOs are regional monopolies. This means
that, in the same way as for the transmission system, the ownership
and operation of the distribution networks is permitted under
licence from Ofgem, the terms of which restrict the revenue of
each DNO. The regulator reviews these revenues every five years
through a Distribution Price Control Review (DPCR) that, when
agreed, establishes a programme of network investment the DNOs
will carry out over the next five years. Ofgem operates an RPI-X
approach, which links DNOs' revenues to the rate of inflation,
therefore encouraging them to make operational efficiencies. One
of the companies, Electricity North West Ltd, told us since privatisation
RPI-X regulation had led to firms halving their work forces and
their costs, while doubling the quality of supply for consumers.
These achievements are significant because electricity distribution
accounts for around 17% of households' bills as opposed to 4%
147. The chief executive of one of the DNOs,
CE Electric UK, told us "After 20 years of radical reductions
the price cannot keep coming down and [
] investments [
need to come forward now".
In 2009 Ofgem conducted its fifth DPCR, which will run from April
2010 to April 2015. One of its objectives is to allow companies
to renew assets that have become age-expired, replacing them with
higher specification equipment that will increase the capacity
of the networks. Scottish and Southern Energy told us the review
needed to provide "a stable platform for investment, adaptation
E.ON UK said: "The framework must also recognise the need
to provide for network developments for both known connection
projects, and also the expected large number of unknown connection
and development requirements".
Electricity North West Ltd expressed a similar view, highlighting
reinforcements in Cumbria and Manchester it could proceed with
which would accelerate the connection of low-carbon generation
in those areas.
148. In December 2009 Ofgem published the outcome
of DPCR5. It has allowed the DNOs to collect revenues of around
£22 billion over the five-year review period. Charges will
rise by an average of 5.6% each year, although this will vary
according to company, ranging from a fall of 4.3% per annum to
a rise of 11.1%. The regulator estimates this will add an extra
£4.30 each year to households' bills. The DPCR also establishes
clear outputs for each of the DNOs which they must deliver in
return for the revenues they will receive from customers. This
means they will not be able to outperform their settlement by
allowing their networks to deteriorate. A key aspect of the review
is the consideration given to the future role of distributed generation
and demand-side management, acknowledging the fact that the previous
regime had encouraged investment in transformers and cables over
other potentially more cost-effective options. One way DPCR5 seeks
to address this is through the equalisation of incentives so the
regulatory framework will treat network investment, network operating
costs and closely associated indirect costs in the same way.
We consider other outcomes of the DPCR in the remaining sections
of this Chapter.
149. We welcome the outcome
of Ofgem's fifth distribution price control review (DPCR), which
seems to balance the requirement for network renewal on the one
hand, with the need to minimise the resulting impact on consumers'
bills on the other. However, the success or otherwise of the DPCR
will need to be assessed against whether it encourages a significantly
greater role for distributed generation and demand-side management
within the energy system over the review period, and the extent
to which it leads to the deployment of smart grid technologies.
The role of innovation
150. The creation of a smart grid will require
significant investment in research, development and deployment
(RD&D) by the transmission and distribution companies. It
is an area where British industry is potentially well-positioned
to be a world leader. The probable large expansion of renewable
power over the next decade, combined with relatively little interconnection
with other countries, means Britain will need to deploy smart
grid technologies sooner than many other countries.
The rewards could be huge. The Department of Energy and Climate
Change estimates the size of the global industry could be £27
billion over the next five years.
However, many of our witnesses told us current levels of RD&D
expenditure by the industry were insufficient and that this was
a direct consequence of the early RPI-X framework, which encouraged
the minimisation of operating costs over the DPCR period by 'sweating
assets', and did not reward investment in innovation that would
reduce firms' costs in the longer term.
151. In the last DPCR Ofgem acknowledged the
impact the regulatory framework had had in running down RD&D
levels by introducing two new incentive mechanisms for network
companiesRegistered Power Zones (RPZs) and the Innovation
Funding Incentive (IFI). RPZs are a way of encouraging distribution
companies to develop innovative ways of connecting distributed
generation. One example is a scheme on the Orkney Islands that
has used active network management technology to allow multiple
renewable generators to connect to the system without the need
for expensive network reinforcement.
The Institution of Engineering and Technology described the RPZs
as "world-class developments".
However, still only a handful have been established in the five
years since the scheme's introduction.
152. The IFI has fared similarly. It aims to
encourage DNOs to invest in R&D that focuses on the technical
aspects of network design, operation and maintenance. The Incentive
allows companies to pass on to customers 80% of their R&D
costs up to a maximum of 0.5% of their total revenues. The industry
has generally welcomed the initiative.
Scottish Power described it as a "resounding success".
Another said it was "excellent".
However, network companies have failed to make full use of the
allowance. In 2007/08 National Grid spent £3 million on R&D,
while the DNOs spent a total of £12.1 million, representing
just 0.33% of their revenue, and well below the £5.4 million
and £20 million respectively available to them. The Minister
told us: "the kindest interpretation is that it reflected
a rather static situation".
Although this represents a sizeable increase since 2005, when
R&D activity for the DNOs totalled less than £1 million
per annum, many feel the industry is still not investing enough
given the scale of future investment required.
As the Institution of Engineering and Technology put it: "There
is [still] little culture of innovation in much of the industry".
153. Whilst the very low base from which R&D
has needed to grow is the primary reason for the slow take-up
of the IFI, witnesses also told us the incentives themselves were
not strong enough.
Furthermore, one DNO described the rules governing the areas they
could innovate in as "narrow and strict".
In response, some have called for the level of the IFI to be significantly
increased up to 2% of network companies' revenues and for its
scope to be widened.
However, in the latest DPCR Ofgem decided to keep it at 0.5%.
The regulator noted in its submission that the underspend by network
companies demonstrated the current provision was sufficient.
It argued also, though, that one of the main challenges was in
encouraging companies to apply the lessons learnt in the laboratory
in commercial demonstrations.
Several DNOs agreed with this view with one telling us: "We
do not need to invent things that do not exist, but we do need
to apply them and really understand how they would work".
154. Accordingly, in the new distribution price
control period Ofgem introduced a £100 million per annum
Low Carbon Networks (LCN) Fund, the aim of which is to encourage
DNOs to trial the new technologies, systems, and commercial and
network operating arrangements that are necessary for the deployment
of the smart grid. The fund will provide 90% of the financing
for projects with DNOs expected to make up the rest. Ofgem will
allocate each of the firms a proportion of the funds, though it
will distribute the majority (around £320 million) through
competition. The regulator also wants the network companies to
share learning and this will be a condition of their receiving
funds. Firms that do not apply the lessons learnt from projects
conducted under DPCR5 will not receive funding for their own trials
in future price control periods.
Ofgem hopes the IFI in combination with the LCN Fund will increase
the level of RD&D within the networks sector to more than
the 2.5% of revenue that is the Government's economy-wide target.
155. Looking to the future, the role of innovation
in delivering the networks needed to support a low-carbon energy
system forms a key part of Ofgem's RPI-X@20 review. The regulator's
current emerging thinking is to introduce a single innovation
stimulus for all the energy networks sectors that builds on the
new LCN Fund. The regulator would also like it to be open to non-network
parties, such as communications companies. Funding would be available
for all types of innovation, ranging from R&D to commercial
156. Elsewhere, the Government has also made
available greater public funding for R&D, including £30
million to support the infrastructure required for low emission
vehicles, and £6 million for a Smart Grid Demonstration Fund.
Further funding is also available through the Technology Strategy
Board and the Energy Technologies Institutea public/private
partnership that aims to invest up to £110 million a year
over the next decade on the development of low-carbon energy technologies,
including the smart grid.
157. The level of research and
development conducted by the networks sector has risen significantly
over the last five years, though still represents just 0.33% of
firms' income. If Britain is to be one of the first to deploy
smart grid technologies on a wide scale, the industry must invest
sufficiently to turn what is at present a vision into a reality.
To the extent that the lack of R&D is a result of the rules
governing companies' expenditure under the Innovation Funding
Incentive, Ofgem should look again at this matter. To the extent
that the underspend is the result of the absence of a "culture
of innovation", the industry must accept that it has failed
in its responsibilities and that it needs to show significant
improvement not just in the interests of both the nation and the
consumer, but also to grasp the huge opportunities that the global
158. We welcome the introduction
of the Low Carbon Networks Fund and the continuation of the Innovation
Funding Incentive. We recommend Ofgem keeps both these mechanisms
under review with the aim of increasing the available funding
for both within the current distribution price control period
if there is demand. We welcome also new public sector funding
for smart grid demonstrations, and hope the Government will continue
to support this area despite the current fiscal constraints.
159. In Chapter 3 we examined how National Grid
levies Transmission Network Use of System (TNUoS) charges on generators
and demand to cover the costs of maintaining and operating the
grid. These charges consist of locational tariffs and additional
flat tariffs, known as the residual. The current framework for
transmission charging treats distributed generation as negative
demand. In other words, it is seen as offsetting local demand.
Because of this, distributed generators do not pay the TNUoS generation
tariff and also usually receive a payment from the TNUoS demand
tariff. In simple terms, because such generators are nearer to
the point of end-use for electricity, they have historically avoided
the charges associated with transmitting power over the transmission
system. This is known as an embedded benefit.
160. Since the establishment of the British Electricity
Trading and Transmission Arrangements (BETTA) in 2005 Ofgem and
National Grid have been concerned about the treatment of distributed
generation within the charging regime. Both believe there is a
case for generators paying the non-locational part of the TNUoS
generation charges, and no longer receiving a payment through
the non-locational part of the TNUoS demand tariff. In other words,
they argue that if generators were charged on a cost-reflective
basis they should only receive a reward from the part of the TNUoS
charges that relate to location. The residual element is the largest
part of the TNUoS charges. National Grid estimates that if distributed
generators only received the embedded benefit from the locational
element of the charges, then it would fall from around £20
per kW to between £6.25 and £7.25 per kW.
161. The regulator has placed a licence condition
on National Grid to implement an enduring set of arrangements
by 2011. Accordingly, in January 2010 the company published a
pre-consultation on modification GB ECM-23, which proposes two
models. National Grid's preferred option would treat output from
distributed generation and transmission-connected generation as
having a broadly similar impact on the need for transmission infrastructure
investment. Distributed generators would pay both the Transmission
Network Use of System (TNUoS) and the Balancing Services Use of
System (BSUoS) generation tariffs that are also levied on transmission-connected
generation, minus a discount that reflected the avoided local
162. The second option would still treat embedded
generation as negative demand, but it would pay for the net electricity
flow that physically passes onto or off the transmission system.
This approach is supported strongly by the renewables industry,
though National Grid believes this option would not treat transmission
and distribution-connected generation in the same way in terms
of the costs they incur across the whole network.
The firm also believes it would be more expensive and time-consuming
to implement. In evidence to the Committee the Minister agreed
that reform of the treatment of distributed generation would be
necessary, stating: "[
] on a network with a lot more
DG capacity, there may be a case for looking at whether the charging
principles as they stand at the moment are right".
163. Generators connected to
the distribution networks do not currently pay transmission network
use of system charges because it is assumed their output is absorbed
by local demand and therefore reduces the need for transmission
capacitya concept known as 'embedded benefits'. The level
of distributed generation, particularly renewables, could increase
significantly in the next decade, to the extent that local supply
will at times exceed local demand, resulting in spillovers back
into the transmission system. Moreover, where renewable generation
is intermittent, transmission capacity will still be necessary
to respond to shortfalls in supply. For this reason, the current
treatment of embedded generation is not sustainable in the long
164. Because the proportion
of distributed generation in the electricity mix is still very
low, there is no need for Ofgem and the industry to reach an immediate
decision on an enduring set of arrangements. Instead, it should
wait until it can be shown clearly that distributed generation
is impacting on the transmission system. We recommend the regulator
develops a set of criteria to determine when it would be appropriate
to reconsider this issue as the risk of change too soon is that
it may exacerbate the 'lock-in' of a centralised energy system.
Central to the debate over the two options proposed by National
Grid is the question of whether in the future there should be
separate regulatory frameworks for the distribution and transmission
networks, or if there is a case for regulating the whole system
as a single entity. The regulator must resolve this question first,
which forms part of its RPI-X@20 review, before it can conclude
on an enduring set of charging arrangements for distributed generation.
241 Ev 152, para 57 (Department of Energy and Climate
Q 235 (Electricity North West Ltd) Back
Ev 151, para 46 (Department of Energy and Climate Change) Back
Q 385 (Minister for Energy) Back
Q 335 (Ofgem) Back
Q 242 (CE Electric UK) Back
Q 296 (Institution of Engineering and Technology) Back
Ev 103, para 7.1 (ABB) Back
Ev 152, para 58 (Department of Energy and Climate Change), Ev
206, para 25 (National Grid) and Ev 258, para 9.4 (Scottish Power) Back
Qq 248 (CE Electric UK) and 41 (Dr Michael Pollitt, Judge Business
School, University of Cambridge) Back
Q 256 (CE Electric) Back
Ev 152, para 56 (Department of Energy and Climate Change) and
Ev 258, para 6.9 (Scottish Power) Back
Q 339 (Ofgem) Back
Q 423 (Minister for Energy) Back
Ev 190, para 41 (Institution of Engineering and Technology) Back
Q 2 (Dr Jim Watson, Sussex Energy Group) Back
Ev 278 (P.E. Baker and Dr B. Woodman, University of Exeter) Back
Ev 264 (Prof Goran Strbac, Imperial College London) Back
Ev 164 and (Energy Networks Association) and Ev 278 (P.E. Baker
and Dr B. Woodman, University of Exeter) Back
Qq 296 (Institution of Engineering and Technology) and (CE Electric
Ev 176, para 3.23 (E.ON UK) Back
Ofcom, Consultation on the way forward for the future use
of the band 872-876 MHz paired with 917-21 MHz, August 2009
Consultation Response by Silver Spring Networks Back
Ev 161, para 6.1 (Electricity North West Ltd) Back
Ev 232 (Scottish and Southern Energy) Back
Q 241 (CE Electric UK) Back
Ev 175, para 3.11 (E.ON UK) Back
Ev 159, para 4.4 (Electricity North West Ltd) Back
Ofgem, Electricity Distribution Price Control Review Final
Proposals, December 2009 Back
Ev 254 (Scottish Power) Back
Department of Energy and Climate Change, Smarter Grids: The
Opportunity, December 2009 Back
Ev 116 (British Wind Energy Association), Ev 164 (Energy Networks
Association), Ev 218 (Dr Michael Pollitt, Judge Business School,
University of Cambridge), Ev 269, para 4.1 (Prof Goran Strbac,
Imperial College London) and Ev 273, para 20 (Sussex Energy Group) Back
Department of Energy and Climate Change, Smarter Grids: The
Opportunity, December 2009 Back
Q 282 (Institution of Engineering and Technology) Back
Ev 112, para 28 (ARUP), Ev 164 (Energy Networks Association),
Ev 177, para 3.28 (E.ON UK) and 202 (National Grid) Back
Ev 259, para 10.1 (Scottish Power) Back
Ev 112, para 28 (ARUP) Back
Q 419 (Minister for Energy) Back
Ev 171 (Energy Technologies Institute), Ev 218 (Dr Michael Pollitt,
Judge Business School, University of Cambridge) and Ev 274, para
25 (Sussex Energy Group) Back
Ev 191, para 50 (Institution of Engineering and Technology) Back
Ev 270 (Sussex Energy Group) and Ev 104 (Areva) Back
Q 245 (CE Electric UK) Back
Ev 202 (National Grid) and Ev 218 (Dr Michael Pollitt, Judge Business
School, University of Cambridge) Back
Ev 216, para 10.2 (Ofgem) Back
Q 333 (Ofgem) Back
Q 231 (CE Electric UK); and also Ev 177, para 3.28 (E.ON UK) and
Ev 259, para 10.4 (Scottish Power) Back
Ofgem, Electricity Distribution Price Control Review Final
Proposals, December 2009 Back
Q 343 (Ofgem) Back
Ofgem, Regulating energy networks for the future: RPI-X@20
Emerging Thinking, January 2010 Back
Ev 152, para 63 (Department of Energy and Climate Change) Back
National Grid, Pre-Consultation: GB ECM-23 Transmission Arrangements
for Distributed Generation, January 2010 Back
Ibid. and Qq 183 (Renewable Energy Association) and 185
(Scottish Renewables) Back
Q 414 (Minister for Energy) Back