3 Transforming transmission
39. Because we do not know yet what the energy
mix of the future will look like, neither do we know with any
certainty how the transmission network will evolve. We have already
identified, however, that there is a risk of continuing Britain's
'lock-in' to a 'big' transmission system if the regulatory framework
does not allow for the possibility of other outcomes. In this
Chapter we consider a range of issues that have concerned policy-makers
in recent years in determining transmission policy.
Investing in capacity
40. Ownership and operation of the transmission
networks in Britain is permitted under licence, the terms of which
restrict the revenue of the licensed network businesses.[53]
The revenue allowed to transmission companies is based on a pre-determined
programme of investment agreed between them and the regulator.
It is reviewed every five years by Ofgem through what is known
as a Transmission Price Control Review (TPCR). The current TPCR
period runs from 2007 to 2013, having recently been extended by
one year. In 2009/10 it will allow companies to recover around
£1.5 billion in revenues. For households, the cost of transmission
equates to around 4% of electricity bills.[54]
Growth in companies' revenues is determined using the RPI-X framework.
This approach has encouraged firms to reduce costs over time through
efficiency improvements. The next TPCR will be based on a new
regulatory framework, arising from the current RPI-X@20 review.
41. Ongoing investment in the transmission network
is necessary to ensure the system remains operational, for example,
through the replacement of ageing or obsolete assets. It is likely
that a system of balancing supply and demand such as BETTA will
continue to operate in the longer term, and therefore new investment
will also be crucial to assist with the migration of less efficient
and older plant towards a marginal supply position on the basis
of continued availability as installed capacity. However, many
within the industry now argue that further investment to expand
the system is required in order to connect the expected growth
in renewable generation in the coming years. In this section we
look at the main barriers to expansion of the transmission network
and the case for further investment.
THE ROLE OF PLANNING
42. The planning system is a fundamental determinant
of whether investment in new transmission capacity is delivered
on time, and was highlighted as a potential barrier by the Department,
the regulator and the industry.[55]
Past experience explains why this is the case. In the 1990s it
took over six years to acquire planning consent for a 50-mile
stretch of new high voltage power lines in North Yorkshire.[56]
More recently, the upgrade of the 137-mile line between Beauly
near Inverness, and Denny near Falkirk, replacing the existing
132 kV cables with high voltage 400 kV lines, entered the planning
system in 2005. Seen as key to allowing the connection of new
onshore wind farms in northern Scotland, the project was first
conceived in 2001, and awarded funding by Ofgem in 2004. Consent
was finally granted in January 2010, which means construction
work could be completed by 2012, when projects would be able to
connect to the new line. From conception to completion, the upgrade
will have taken 11 years.[57]
Smaller projects have also faced difficulties. Scottish Power
told us about a 20 km wooden pole line it wished to build between
Lostock and Carrington in Lancashire.[58]
The company submitted its planning application in 2003, but is
not expecting to receive consent until later in 2010.
43. Overall, many of our other witnesses were
highly critical of the planning process. The Scottish Chambers
of Commerce described it as "sclerotic".[59]
Another witness said that, left unaddressed "the planning
system is likely to thwart aspirations for connecting renewable
generation".[60]
Elsewhere, Scottish and Southern Energy told us: "The shortcomings
of the planning systems need to be addressed if the UK is to meet
the EU 2020 target and longer-term security of supply and climate
change goals".[61]
44. Several organisations, however, sought to
defend the planning system. Scottish Natural Heritage, for example,
told us the length of inquiry into the Beauly-Denny line was partly
the result of the transmission companies having not undertaken
sufficiently thorough exploration of alternative options, such
as burying cables underground in areas of environmental sensitivity.[62]
The Campaign to Protect Rural England (CPRE) noted that the delay
to consenting the North Yorkshire line had been the result of
the developer having to consider ways of lessening the impact
of the line on the landscape that it had not fully addressed in
its initial proposal.[63]
Both organisations rejected the idea that the planning process
should be considered a 'barrier' to network expansion—rather,
as CPRE told us: "it is a vital means of ensuring that the
future development of the transmission network takes full account
of the public interest".[64]
45. In order to address some of the concerns
with the current planning system, the Planning Act 2008
established an independent Infrastructure Planning Commission
(IPC), which will operate a streamlined consenting process. Under
the new arrangements Ministers will retain responsibility for
the policy framework, which will be set out in National Policy
Statements (NPSs). The IPC will make decisions on consents based
on these NPSs, which will set out the need for the infrastructure
and how the IPC should consider impacts. Consultation on applications
will be required before they are submitted to the IPC, and guidance
given on what constitutes a good application. The hope is that
this will mean the Commission can consider applications more quickly,
which it will do within set timetables.[65]
The Government published the draft NPS on electricity networks
infrastructure in November 2009, as part of a suite of energy
NPSs.[66] They are subject
to consultation and parliamentary scrutiny, for which this Committee
is playing a key role, before likely designation sometime in 2010.
46. Only planning applications for power lines
in excess of 132 kV, or network infrastructure that is associated
with a nationally significant power station, will be subject to
approval by the IPC. This means that consenting for lower voltage
distribution lines will still fall to local planning authorities.
The new system applies only to England and Wales. In Scotland,
reform has also taken place: measures announced in 2008 include
the requirement for promoters of major developments to conduct
a consultation with the community before submitting the planning
application. A statutory four-month time period for a decision
on applications will also be put in place. Other reforms in Scotland
include: simpler and more transparent processes; quicker decision-making
by councils on high-quality applications; a greater focus on matters
of national interest; and up-to-date development plans to provide
investors and communities with greater certainty. In 2009 the
Scottish Executive also published its second National Planning
Framework (NPF2), which designated 14 national developments of
strategic importance to Scotland, of which electricity grid reinforcements
was one.
47. The network industry broadly welcomed reform
of the planning system.[67]
There is a high level of expectation on the ability of the changes
to speed up the planning process. E.ON UK told us: "The success
of the new IPC planning process […] will be key to the delivery
of major infrastructure projects".[68]
Scottish and Southern Energy said: "The importance of the
National Policy Statements cannot be overemphasised […] the
NPSs must be clear and have sufficient depth to form the basis
for authoritative decisions".[69]
The Association of Electricity Producers noted its concern, though,
that there remains a disjointed approach between the systems in
England and Wales and Scotland, with varying timescales, considerations
and processes. It believed greater consistency was needed.[70]
48. Reform of the planning process
is vital if network improvements are to be delivered on time to
connect new generating capacity in the future. We note the recent
changes to the planning systems in England and Wales, and Scotland,
and are pleased to be playing a role in scrutinising the draft
National Policy Statement for Electricity Networks Infrastructure.
We hope the new system will lead to a faster decision-making process,
but one that nonetheless will take account of the environmental
concerns associated with new proposals. For this, developers have
a duty to ensure their initial applications take adequate account
of alternative options. The Government should also look closely
at the consenting process for applications in England and Wales
that will not fall to the Infrastructure Planning Commission to
see whether reform or improved guidance is necessary at this level
as well.
STRATEGIC INVESTMENT IN TRANSMISSION
49. Under the existing TPCR framework investment
is reactive—transmission companies do not undertake reinforcement
or line extension work until individual generating companies have
guaranteed they will meet the cost of those connections.[71]
This approach, whereby network capacity is expanded only if there
is a power plant ready to use it, has helped reduce the risk of
investment capacity not being utilised, otherwise known as stranded
assets.[72] However,
this can cause problems for generating companies that are not
able to guarantee their connection until they are confident their
projects will proceed, for example, once they have received planning
permission. We have already seen, though, that the consenting
process for new grid capacity can take time. This can lead to
a mismatch between when a project is ready to connect to the grid,
and when the grid capacity is available to connect it. The problem
is exacerbated by the fact that, as the share of renewables in
the electricity mix expands, transmission reinforcement is being
driven increasingly by a large number of relatively small projects.[73]
50. The existing regulatory framework is now
affecting the ability of transmission owners to provide connections
in the necessary locations.[74]
For example, National Grid told us: "A more flexible mechanism
is required to deliver the infrastructure investment in our vision".[75]
This would also align better the construction programmes of the
transmission companies and power station developers. Accordingly,
a consensus has emerged within the industry in support of strategic
investment in grid capacity—that is, investment ahead of
individual projects being able to give specific financial commitment
for their connections.[76]
This is possible because the general geographical location of
a significant amount of future renewable generation, particularly
wind power, is already well known.
51. To identify where areas of investment were
required, in 2008 Ofgem and the Government asked the Electricity
Networks Strategy Group (ENSG)—a senior industry group—to
consider what the transmission system would need to look like
to meet the 2020 targets for renewable energy. The ENSG published
the first phase of its work in March 2009. It identified reinforcement
work for a range of projects in areas of Scotland, Wales, East
Anglia, London and the South West. It includes potential high
voltage subsea cables between Scotland and the north of England
along both the east and west coasts. In total, the work could
amount to £4.7 billion between now and 2020. This is in addition
to network investments already approved to connect renewable generation
and through the current transmission price control. Combined,
the cost of this work would be equivalent to the asset value of
the existing transmission system—potentially the biggest
grid development since the Second World War.[77]
It is also worth noting that this excludes the cost of connecting
future offshore wind. The report notes that provided the work
is taken forward in a timely manner, subject to planning consent,
the reinforcements could be delivered within the required timescales.
They would be phased over the next decade with the resulting network
able to accommodate between 29 and 45 gigawatts of new generating
capacity.[78]
52. The ENSG work has received widespread support
from the industry.[79]
E.ON called for transmission companies to be permitted immediately
to commence with pre-construction work for the projects identified.[80]
Scottish Renewables said: "It is important […] that
work on these upgrades and reinforcements should start as quickly
as possible".[81]
Ofgem responded in April 2009 by approving up to £12.5 million
of funding outside the current TPCR for the transmission companies
to begin feasibility studies and preparatory work. Since then
the regulator has been working with the firms to establish longer-term
funding arrangements that will facilitate a programme of strategic
investment. In January 2010 the regulator approved additional
funding of up to £1 billion for construction work on specific
projects.[82] Further
investment will be funded through the next TPCR, due to begin
in April 2013. A key part of Ofgem's work will be to ensure that
additional funding does not lead to the construction of unused,
stranded assets. In its evidence to us the regulator acknowledged
that its new approach entailed making a judgement on the level
of stranded asset cost that was reasonable to incur for consumers,
and that this represented "a fundamental philosophical shift"
in its regulation of network investment.[83]
HOW STRONG IS THE CASE FOR INVESTMENT?
53. Although there was a consensus between the
generators and network companies in favour of significant new
investment in transmission reinforcements, this view was not shared
by all who gave evidence to the Committee. For example, Dr Michael
Pollitt told us a key concern should be "making sure that
we do not […] give network incumbent companies a licence
to massively increase capacity, which might not be necessary".[84]
Prof Strbac noted too that the ENSG work presents a solution that
involves a 'business as usual' response by the industry that is
a direct consequence of the existing regulatory framework.[85]
Although both acknowledged that investment in the network infrastructure
will be needed, they also believed that, in addition to new capacity
through network reinforcements, a range of other solutions that
can release latent network capacity should also be considered.
These include, for example, the application of a variety of operational
measures, emerging local generation coming on stream, or allowing
a greater role for responsive demand—all of which could
substitute for network investment.
54. A further important concern raised by Phil
Baker and Dr Bridget Woodman at the University of Exeter was that
existing network assets should be fully utilised before making
the case for further investment.[86]
The GB Security and Quality of Supply Standards (SQSS) set out
the criteria and methodologies that National Grid must use in
the planning and operation of the electricity transmission system.
In other words, they determine the level of transmission asset
utilisation. Baker and Woodman told us there is scope to improve
the utilisation of the existing transmission assets.[87]
One example could be a move towards weather-related security standards.
At present around 70% of transmission faults relate to weather
conditions. However, the weather is not taken into account when
operating the transmission system, even though it may be possible
to relax operational security standards during fair-weather conditions,
and so release latent network capacity. Such an approach could
significantly decrease the external costs of operating the transmission
system and reduce the need for investment without posing a risk
to customer supplies.
55. Another way of releasing latent capacity
from the existing network is through the use of special protection
schemes. These are intelligent tripping systems that mitigate
unexpected faults that could lead to a disconnection of a transmission
line by automatically tripping generation or shedding demand load
from elsewhere on the system. Although limited in scope at present,
network operators already use some of these technologies to enhance
the capability of their existing systems. Worldwide, there is
growing interest in the development and application of such approaches,
which entail more sophisticated system operation, but also minimise
or avoid the need for network reinforcements. Solutions such as
special protection schemes are more widely used in other parts
of the world, including the US, Brazil, Chile, Australia and Taiwan,
thus allowing system operators to achieve a higher level of network
utilisation.
56. Prof Goran Strbac argued that the SQSS, which
have remained largely unchanged since 1948, present a barrier
to a range of other solutions that could release latent capacity
from the existing network.[88]
Among others, these include more sophisticated system operation,
such as the application of advanced network control, protection
and maintenance techniques and innovative decision-making tools.[89]
They also include non-network solutions such as the greater role
of demand in managing the electricity system as discussed in Chapter
2. This is important because these alternative approaches could
not only enable the release of latent capacity from the existing
transmission assets and facilitate the connection of greater amounts
of wind power in the short term, but also in the longer term play
a key role in the development of a smart grid.
57. Phil Baker and Dr Bridget Woodman also criticised
the incentives in place for new transmission capacity.[90]
At present the regulated income of transmission operators through
the transmission price control review (TPCR) is a function of
the value of their asset base. This, therefore, places an incentive
on companies to grow that base by building as much transmission
capacity as they can justify, rather than actively looking for
operational alternatives. In June 2008 the transmission companies
began a fundamental review of the SQSS. This could provide a major
opportunity to reform the Standards to maximise utilisation of
the existing network and encourage the take-up of smart grid technologies.
The review team's terms of reference set a target date of September
2009 to report and consult on detailed proposals.[91]
These have not yet been published. We note that the ENSG work
that proposes significant strategic network investment is based
on the existing SQSS.
58. To avoid delays in connecting
new power stations a more strategic approach to investment in
transmission capacity is necessary. We welcome the Electricity
Networks Strategy Group's work to identify the reinforcements
it believes are needed in the next ten years. We also note Ofgem's
cautious approach in allowing funding to advance particular projects
and we urge them to be more proactive in promoting ways of avoiding
delays.
59. Given the costs involved,
the resulting impact on customers' bills, and the risks of delay,
it is vital the case for investment is as robust as possible and
preferable to any alternatives. There is some concern that the
existing regulatory framework is driving the case for transmission
investment presented by the industry at the expense of other more
cost-effective options that seek better to utilise the existing
network infrastructure. The current fundamental review of the
Security and Quality of Supply Standards (SQSS) presents a major
opportunity to address these issues. However, the review, which
had aimed to publish detailed proposals in September 2009, has
not yet reported. Therefore, we are concerned that some of the
currently proposed strategic network investment that is based
on the existing SQSS may prove unnecessary. Furthermore, reform
of the SQSS will be vital for the development of a future smart
grid. It would be totally unacceptable if Ofgem failed to fulfil
its duties to consumers by not ensuring the timely completion
of this review, especially as the regulator has already begun
to grant funding for additional investment. We consider it essential
that consideration of new investment in transmission has the benefit
of the outcome of the SQSS review and strongly recommend that
urgent measures are taken to complete and publish the review.
Network charging
60. On connection to the GB transmission system,
generators are required to pay the following charges:
- Connection Charges: These enable
National Grid to recover the costs involved in providing the assets
that allow connection to the transmission system.
- Balancing Services Use of System (BSUoS): This
charge recovers the cost of balancing demand and supply across
the system.
- Transmission Network Use of System (TNUoS): This
charge recovers the cost of installing and maintaining the transmission
network required to allow the bulk transfer of power between sites
and to provide transmission system security.[92]
In this section we focus on current issues concerning
the second and third of these charges.
CONSTRAINT COSTS
61. The transmission system has a finite capacity
to transport electricity between power stations and consumers.
Constraints can occur when the system is unable to transmit the
power supplied at a particular location to where demand for it
is situated. This may be because heating ratings on electricity
lines have been exceeded, or because of an inability to maintain
voltages on the system within the limits set out in the GB Security
and Quality of Supply Standards (SQSS) discussed in the previous
section. Constraints can also be exacerbated by transmission outages
arising, for example, from network reinforcements, or unexpected
generation failure. When such constraints occur National Grid,
the system operator, will take action to reconfigure the system
and/or go to the wholesale electricity market to increase or decrease
the amount of electricity being supplied to the system at different
locations.[93] If National
Grid has to require a power station to reduce its output because
of constraints on the transmission network, the generator is compensated
for the reduction in the grid's capability to take their full
output. The costs incurred are referred to as constraint costs.
Along with all the other costs associated with keeping the system
in balance and maintaining security of supply, these are passed
onto users of the system through Balancing Services Use of System
(BSUoS) charges. They are paid equally by generators and consumers,
and do not vary by location.
62. In recent years the level of constraint
costs have risen from £70 million in 2007/08 to £262
million in 2008/09 and are forecast to be £198 million in
the current financial year.[94]
Constraint costs have caused growing concern for Ofgem since
the establishment of the British Electricity Trading and Transmission
Arrangements (BETTA) in 2005. The Arrangements brought together
the electricity markets for Scotland, England and Wales. Under
the regime, generators self-despatch their plant. In other words,
they have guaranteed access to the grid, except at times when
they are constrained off by the system operator. Because the interconnection
between England and Scotland, known as the Cheviot Boundary, does
not have the capacity to always meet the demands placed on it
by electricity flows between the two countries, Ofgem has issued
the boundary a derogation from the requirement to comply with
the Security and Quality of Supply Standards (SQSS).
63. Constraint costs are key to informing investment
decisions in new network capacity.[95]
Accordingly, an investment programme is underway to upgrade the
Cheviot Boundary as this is seen as a main pinch-point on the
network. It is important that constraint costs send the right
signal of investment needs. The evidence we received suggest two
factors have contributed to the level of these costs being higher
than they otherwise could be—the inherent nature of BETTA
and the alleged exploitation of market power by the Scottish transmission
companies.
64. One of the key differences between the BETTA
system and the electricity 'Pool' trading arrangements that preceded
it is that the market does not explicitly reward companies for
providing generating capacity. Indeed, the debate on the future
of BETTA includes substantial argument that a new system able
to cope better with variable demand may need, at least in part,
to reward installed capacity. Phil Baker and Dr Bridget Woodman
at the University of Exeter argue that this means firms must instead
attempt to recover some of their investment costs through the
BETTA market. However, in an efficient market constraint costs
should only be driven by fuel costs—i.e. the relative difference
it costs for, say, a coal-fired power station in southern England
to generate, versus a similar plant in Scotland. They note that
the costs of resolving transmission congestion are observed to
be around £90 per MWh, whereas under an efficient market
only costs of £10 per MWh should apply.[96]
Similar work conducted by the Centre for Sustainable Energy and
Distributed Generation demonstrates the same effect.[97]
This implies that BETTA potentially overstates the true level
of constraint costs and, therefore, the need for additional transmission
capacity to meet these constraints may also be overstated.
65. Ofgem also believes constraint costs have
been made artificially high in recent years through the exploitation
of market power by certain electricity companies. In April 2008
it launched a formal investigation under the Competition Act
1998 into the behaviour of Scottish Power and Scottish and
Southern Energy. The complainants alleged that the companies may
have withheld generating capacity from the wholesale forward market
while using the same plant to supply balancing power to National
Grid at excessive prices.[98]
Ofgem closed the investigation in January 2009, stating that to
continue would have been an inefficient use of resources given
the low likelihood of making an infringement decision under the
Act.[99] Nevertheless,
the regulator estimates that up to £125 million of the £262 million
of constraint costs incurred in 2008/09 could potentially have
been the result of the misuse of market power.[100]
Because of the difficulties Ofgem believes it faces in applying
the Competition Act 1998 legislation to the wholesale electricity
market, it has argued in favour of being able to place a Market
Power Licence Condition on generators that would strengthen its
ability to carry out investigations.[101]
The Energy Bill currently before Parliament includes provisions
which would give the regulator these powers.
66. In February 2009 Ofgem wrote to National
Grid highlighting concern at the level of constraint costs, and
asked it to conduct a review considering possible changes in the
way they are recovered. In May the company proposed a modification
to the BSUoS charging methodology—referred to as GB ECM-18.
This would see constraint costs that arise from the non-compliance
of a derogated transmission boundary, such as the Cheviot interconnection,
being levied on a locational basis to all exporting generators
behind that boundary. Ofgem is now consulting on this proposal
and expects to make a decision before the start of the next charging
year on 1 April 2010.[102]
67. If implemented, GB ECM-18 will inevitably
shift the burden of BSUoS charges from generators in England and
Wales onto those in Scotland. Depending on how generators respond,
it will also potentially reduce the level of constraint costs
across the system by encouraging less generation north of the
border and more in the south. National Grid also believes the
reforms would reduce companies' ability to exercise market power
when the system is constrained.[103]
The proposals met with criticism from some our witnesses. Scottish
Renewables told us: "It is conceivable that generators behind
a number of boundaries will face significant additional […]
charges which may cause the suspension of a number of projects".[104]
However, National Grid's analysis suggests that though wind generators
in Scotland would pay more, it would be marginal thermal (i.e.
fossil fuel-based) plant that would be incentivised to generate
less.[105] Scottish
Power, which would be most affected by GB ECM-18, also expressed
concern stating: "[...] we do not see ourselves as a cause
of the balancing costs. We are unable to generate as much as we
would like because the network is not strong enough".[106]
However, others were in favour of greater locational pricing within
the BSUoS charges, noting that the current system, which does
not minimise constraint costs, creates incentives for inefficient
investment in transmission assets.[107]
Prof Strbac also argued that moving towards locational BSUoS charges
would facilitate greater sharing of network capacity by, for example,
encouraging conventional power stations in Scotland to reduce
their output on windy days.[108]
He also considered that, in the future, the sharing of network
capacity between generators will be a key feature of the smart
grid.
68. It is also worth noting that once the current
upgrade of the Cheviot Boundary is complete it is possible that
it will then comply with the SQSS and no longer require a derogation.
Given the locational charges under GB ECM-18 apply to a derogated
boundary, many of the concerns raised by the Scottish generators
may prove unfounded in the long run. The debate may also be superseded
by new charging arrangements that could arise from DECC's consultation
on an enduring access regime for new generators, which we discuss
later in this Chapter.
69. Constraints occur on the
transmission network when the system is unable to transmit the
power supplied at a particular location to where demand for it
is situated. National Grid's management of these constraints gives
rise to costs, which are met by generators and consumers. The
level of constraint costs are an important signal of investment
needs. It is, therefore, vital that this signal is accurate. We
are concerned that the nature of the British Electricity Trading
and Transmission Arrangements (BETTA) appear to artificially inflate
the level of constraint costs. We note the general review of the
BETTA market announced by the Government in the Pre-Budget Report
in December 2009. However, we recommend Ofgem conducts a specific
review of the BETTA market with a view to addressing this issue.
We also support the Government's intention to enhance Ofgem's
powers to regulate against companies artificially inflating constraint
costs.
70. Whilst we agree in principle
with the current proposals to implement locational pricing for
the Balancing Services Use of System charges as a means of reducing
constraint costs in the short run, we question whether Ofgem should
continue to pursue the modification brought forward by National
Grid, given it could be replaced by another set of charging arrangements
in the short to medium term when DECC implements a new regime
for determining transmission access.
TRANSMISSION NETWORK USE OF SYSTEM
CHARGES
71. The amount transmission companies can spend
on operating and maintaining the system, as well as investment
in new network capacity, is set through five-yearly price control
reviews. These costs are recovered from both generators and suppliers
through Transmission Network Use of System (TNUoS) charges. In
2009/10 the amount collected through these charges will be over
£1.4 billion, representing around 3-4% of electricity customers'
bills.[109] From April
2009, the TNUoS generation tariff has comprised four separate
elements. Three of these vary according to the location of the
generator on the system, the largest component of which is the
'wider' locational charge, which varies from £21.59 per kW
in North Scotland to a negative charge of £6.68 per kW in
the Cornish Peninsula. These locational charges will net around
£85 million of revenue in 2009/10. The remaining component
of the TNUoS generation tariff is a residual charge, which is
non-locationally specific, and is paid at a flat rate. This raises
a further £300 million. Generators pay 27% of total
transmission costs with the rest met directly by consumers through
electricity suppliers—around £1,041 million in 2009/10.
72. The locational element of the TNUoS charges
was the source of considerable debate in the course of our inquiry.
The tariff is in place because National Grid's licence obligations
require it to charge its customers cost-reflectively.[110]
Higher costs in the north are meant to reflect the greater cost
of transporting electricity across longer distances to centres
of demand in the south, where network capacity is also greater.
In so doing, the TNUoS charges are designed to provide an economic
signal to generators and developers to work within existing network
capabilities and locate nearer to the source of demand. This then
reduces the need for investment in new network capacity, which
can be expensive and time-consuming to deliver as has been the
experience to date, for example, with the Beauly-Denny Line. It
also has potential environmental benefits, both in decreasing
the transmission losses arising from the transport of electricity
over long distances, and in reducing the need for new pylons that
can blight the landscape.[111]
73. Both Ofgem and the Government argued strongly
in favour of cost-reflective transmission charges. The regulator
believes it promotes efficient development and use of the network,
which is in the interests of current and future consumers.[112]
The Minister told us: "If we do not have a signal that helps
people think […] about how and where they will locate their
plant, then there is a risk obviously that we get too much investment
in areas across the system that are too far from demand".[113]
In their evidence to us, organisations including the Association
of Electricity Producers, the Institution of Engineering and Technology,
the Renewable Energy Association and E.ON UK, among others, also
supported the principle of locational pricing.[114]
74. Generators in Scotland have, by contrast,
been highly critical of the locational element of the TNUoS generation
tariff, arguing that it creates an uncertain environment for investment
and discriminates against renewable generation. Scottish Renewables
argued that some forms of renewable energy, such as wind, are
not able to respond to the locational price signal in the same
way that gas-fired power stations can. The trade union Prospect
told us that locational pricing is "a legitimate mechanism
for encouraging construction of fossil fuel fired or nuclear generation
near the load centres, but acts as an additional disincentive
to remote renewable generation".[115]
Scottish Renewables argued this results in income derived through
the Renewables Obligation in Scotland effectively being transferred
to conventional generators in the south.[116]
Scottish and Southern Energy too were critical of the level of
locational tariffs, noting that the current approach had created
charges that were "volatile and unpredictable".[117]
The company told us this acted as a deterrent to investment by
generators and that this uncertainty also undermined the signals
for investment in additional transmission capacity.[118]
75. With the support of the Scottish generators,
in 2008 the Scottish Executive brought forward a proposed modification
to National Grid's transmission charging methodology, known as
GB ECM-17. This proposed an alternative model based on a 'postage
stamp' approach to charging where a GB-wide tariff is levied for
each unit of energy exported onto the network. Scottish Renewables
argued this would create a regime that was "proportionate,
predictable and stable and will do much to promote new generation
in the UK".[119]
It would also reduce transmission charges for generators in Scotland.
Socialising the cost of transmission across all generators, irrespective
of location, is also the approach used in countries such as Germany.[120]
National Grid consulted on the proposal in 2009. It found that
cost reflective charging was still consistent with the Government's
objectives for increasing renewable generation and reducing carbon
dioxide emissions, and that the existing approach did produce
tariffs that were stable and predictable for the vast majority
of sites. The company, therefore, rejected the modification.[121]
76. Ofgem was highly critical of 'postal charging'
for transmission access.[122]
The regulator argued such an approach would discriminate unduly
against generators in the south who impose lower costs on the
system, whilst also creating incentives for over-investment in
transmission capacity in the north. It also noted the mirroring
of charging methodology for gas transmission, where gas users
in Scotland benefit from lower charges than those further south
because they are closer to the major entry points to the gas transmission
system. Ofgem told us it would be difficult to justify changing
the charging approach for electricity without doing likewise for
gas.
77. Some witnesses suggested that the level of
transmission charging did not target costs to location enough.
Prof Strbac told us the revenue derived from the locational element
of the TNUoS charge was small relative to the revenue from the
residual charge, which is spread across all generators—£85
million as opposed to £300 million.[123]
This in turn is dwarfed by the £1,041 million of transmission
charges paid by consumers. Dr Michael Pollitt noted too that the
potential growth of offshore wind meant generators had many more
options of where to locate new renewable capacity and, therefore,
respond to locational signals.[124]
The Renewable Energy Association also told us that whilst Scotland
is an extremely important resource for renewable energy, "it
is not, however, the only show in town".[125]
78. The Department and Ofgem argued that locational
charges were not harming the development of renewable generation
in Scotland. DECC stressed that the nature and level of the TNUoS
charge and other related transmission-related costs were taken
into consideration when determining the level of subsidy available
through the Renewables Obligation.[126]
The regulator's Chief Executive told us proposed onshore wind
projects as far north as Orkney typically had estimated rates
of return on investment of up to 40%, in contrast to around 12%
for a gas-fired power station.[127]
Moreover, access to finance in the current economic climate, gaining
planning consent, and securing a grid connection are all seen
as more important determinants of investment in new renewable
generation.[128]
79. However, the treatment of wind generation
specifically within the charging regime was raised as a concern.[129]
At present, generators are charged according to their peak load
condition—i.e. the output they contribute to meeting peak
demand. Yet wind generation is variable in nature, having a low
load factor of around 30%, and so makes a low contribution to
peak demand. This is not, though, reflected in the network charges—if
it were wind generators would pay significantly less.[130]
National Grid acknowledged this concern in its Conclusions Report
on GB ECM-17.[131]
Whilst this may not be a significant factor in determining the
investment case for new wind generation at present, it could become
more so as financing conditions ease, and reform of the planning
system and grid access regime are implemented. We discuss the
latter of these in the next section.
80. We are concerned that the
current system appears to charge wind generators disproportionately
more than conventional generators for grid usage. We believe that
it is imperative that transmission charges should not discriminate
against renewable energy wherever it is located in Britain. Whilst
we received conflicting evidence on this matter and acknowledge
that other factors such as the planning system, grid access and
financing play an important role in determining the investment
case for new renewable generation, we believe it is vital that
this issue be fully investigated as soon as possible. We note
Ofgem's long-term commitment to the model of locational charging,
but given the evidence we have received we recommend the Department
establishes an independent review to develop an appropriate transmission
charging methodology.
Grid access
81. Access to the network is vital for electricity
producers as without it they cannot deliver their product to consumers,
nor do they have confidence to invest in new generating capacity.
The issue also ties closely with the case for investment in new
transmission assets and the network charging regime. In this section
we look at the problems new generators face in acquiring network
connections and the Government's response to these concerns.
THE QUEUE FOR NETWORK ACCESS
82. Under the existing transmission access arrangements
the grid operator follows an 'invest and connect' approach for
new projects whereby they are only connected if there is sufficient
grid capacity to accommodate their maximum potential output without
causing a restriction on the production of existing generators.[132]
The speed with which a generator can gain access will depend on
the amount of grid reinforcement needed; the ease with which planning
consent can be acquired for any work; and the amount of generating
capacity applying to connect in each part of the network.[133]
Unless there is already spare capacity on the grid, generators
must wait until the operator has made the requisite reinforcements
before they can connect. Those applying for access are treated
on a first-come-first-served basis, which means projects that
are less viable can block those that are further ahead or could
be advanced earlier. Indeed, the position is rather similar to
people booking rooms in hotels before they have found out whether
they can get the time off work.
83. These arrangements have resulted in a queue
of projects at various stages of development waiting for connection
with a combined capacity estimated at between 60 GW and 80
GW—equivalent to all Britain's existing generating capacity.[134]
Around 17 GW of this is renewable generation, with some projects
holding a connection date as late as 2023. At present half of
the queue will have to wait at least five years for grid access.[135]
In Scotland 9 GW of renewables is waiting for connection, a large
proportion of which has connection dates later than 2018.[136]
Many projects with connection offers do not come to fruition.
However, even with an attrition rate of 50% assumed by several
of our witnesses, the backlog of schemes is long. For projects
in Scotland the queue is primarily the result of the delayed upgrading
of the Beauly-Denny line and the Cheviot Boundary. Scottish Renewables
estimate that once the former of these is in place more than 5
GW of renewables in Scotland will be able to connect to the system.[137]
Scottish Renewables told us: "If you apply a planning attrition
rate of 50% to the 9 GW [...] then these reinforcements will be
sufficient to provide the necessary firm access".[138]
84. It is clear that the existing regime creates
considerable uncertainty for both renewable and conventional generators
and restricts access to the energy market. As one independent
generator said: "This makes continued investment in the UK
very difficult in comparison with some other jurisdictions".[139]
Scottish and Southern Energy told us: "[...] it is not surprising
that potential investors (particularly in emerging renewable technologies)
are opting to locate elsewhere in the global energy market".[140]
The Government and the regulator have recognised the need for
change.[141] Accordingly
in 2008 they launched the Transmission Access Review (TAR), the
aim of which was to provide a programme of reform that would significantly
reduce grid access barriers. The TAR process is still underway.
It was meant to deliver both short-term measures to reduce the
current queue, as well as an enduring access regime for the long
term. We consider each of these in the next two sections.
INTERIM MEASURES
85. In the debate over improving grid access
one approach has come to the fore, at least as a short-term solution—the
concept of 'connect and manage'. This can take a variety of forms,
though the common basis is that all generators who wish to connect
to the grid are allowed access irrespective of whether any necessary
transmission reinforcements have been completed.[142]
In so doing both existing and new generators have firm access
rights. The system operator manages any resulting congestion on
the network on a day-by-day basis by taking offline generating
capacity where there are pinch-points, for which the owners are
compensated—these give rise to the constraint costs discussed
earlier in this chapter. This is the approach currently used in
Germany and Denmark.[143]
86. In May 2008 Ofgem announced that it had approved
National Grid's proposal to introduce changes to the rules on
connections known as 'interim connect and manage'. This will enable
both renewable and conventional generators to link to the grid
as soon as their local connections are ready, rather than wait
until any wider system reinforcements have been completed. The
regulator expects the measures to be in place only in the short
term in anticipation of their replacement with an enduring access
regime in the near future. Initially, the combination of this
and more proactive queue management by National Grid allowed around
450 MW of renewable projects to gain earlier connection dates
in Scotland.[144] National
Grid has now identified a further 450 MW of renewable projects
that can connect earlier than expected. This constitutes about
a fifth of the current queued capacity in Scotland that could
be delivered in the next decade (again, assuming a 50% attrition
rate).[145]
87. Overall, the industry has welcomed the introduction
of the interim measures.[146]
There has, however, been some concern over the level of constraint
costs that will arise from their implementation.[147]
Where other countries have introduced 'connect and manage' it
has led to a significant increase in network congestion and associated
constraint costs.[148]
The extent of these will be determined by the time it takes for
planned investment in new capacity to take place and, before then,
by how the costs are distributed across network users. We have
discussed already in this Chapter National Grid's proposal to
make the Balancing Services Use of System (BSUoS) charges locationally
determined, rather than socialised across all generators. The
level of anticipated constraint costs arising from the 900 MW
of additional renewables capacity, and hence the impact locational
pricing might have, has been a matter of disagreement between
the industry and the regulator.[149]
Moreover, National Grid believe locational pricing within the
BSUoS will have a greater effect on conventional capacity in Scotland
than on renewables. However, debate over these issues is likely
to be superseded by the introduction of a long-term access regime.
AN ENDURING ACCESS REGIME
88. The arrangements by which generators gain
access to the network are set out in the Connection and Use of
System Code (CUSC). This is a modifiable document such that Ofgem
can change any part of the access regime. However, it can only
do so with amendments proposed to it by the industry—the
regulator cannot change the CUSC of its own accord. This meant
it was the industry's responsibility to lead on developing an
enduring access regime. As an incentive the Government included
in the Energy Act 2008 a provision for the Secretary of
State to impose a regime if the industry failed to develop a satisfactory
solution.
89. National Grid began the process by proposing
in April 2008 a suite of amendments to the CUSC which over the
course of 2008 and 2009 were discussed and developed by industry
working groups. The regulator's role was to monitor and report
on progress to the Department. In early 2009 it became apparent
to Ofgem that the emerging proposals for enduring reform would
lead to significantly higher network charges for low-carbon generation,
particularly renewables, than for conventional generators. In
evidence to us in May the regulator's Chief Executive referred
to analysis by National Grid suggesting that one of the proposed
approaches would give rise to charges of £70 per kW for a
wind farm in Scotland versus £10 per kW for a generator in
England and Wales. He described this kind of outcome as "absurd".[150]
Frustrated by what it saw as the industry's unwillingness to engage
in other options, in June 2009 the regulator wrote to the Secretary
of State recommending he use his powers under the Energy Act
2008 to take action into his own hands. In his letter the
Chairman of Ofgem, Lord Mogg, wrote: "The electricity generation
sector must clearly play a major role in delivering the UK's ambitious
emission reduction targets and it is regrettable that the industry
appears to have fallen at the first hurdle".[151]
90. Accordingly, in August 2009 the Department
published a consultation setting out three possible variations
of the 'connect and manage' model, summarised below:
- Socialised—A
model that fully socialises any additional constraint costs. Under
these arrangements costs would be shared between all users of
the network and ultimately borne by consumers;
- Hybrid—This
targets some, but not all, of the additional constraint costs
on new entrant power stations; and
- Shared cost and commitment—This
offers the choice to new and existing power stations to commit
to fixed network access in return for greater certainty over charges,
or to opt out and be exposed to additional constraint costs.[152]
91. The Department's consultation came after
the Committee had completed its evidence-gathering. We note, though,
Ofgem's recent response to the consultation.[153]
This expressed concern that all three of the approaches would
create significant additional constraint costs in the range of
£2.9 billion to £3.5 billion between 2009 and 2020 (on
a net present value basis), which it states would ultimately be
borne by consumers. It argues too that until additional grid capacity
is in place these regimes would create opportunities for generators
to exploit market power and increase constraint costs further.
Furthermore, the regulator criticises the Department for failing
to take a holistic approach in its proposed reforms. For example,
they fail to address wider issues concerning the current arrangements,
including the nature of access rights; the way in which generators
commit to use the system and the costs of doing so; and the compensation
they receive when constrained off the network.
92. There are a variety of ways in which the
Department could define a long-term grid access regime. For it
to be successful, however, the evidence we received suggests it
should contain four key features. First is the principle of generators
sharing access to the network. While the development of the smart
grid will reduce the need for investment in generating capacity
significantly over a continuation of the current approach of building
supply to always meet peak demand, it is still the case that total
generating capacity in the future is likely to be higher than
it is now for a given level of demand, primarily because of the
intermittency of wind generation. DECC's memorandum suggests Britain's
total capacity could be around 105 GW in 2020 for current levels
of demand, compared to 80 GW today.[154]
Consequently, the Department believes there is an opportunity
to share network access more efficiently. In so doing this reduces
the need for new investment in transmission capacity.
93. Sharing access represents a move away from
the current approach whereby all generators have guaranteed entry
rights to the grid and are compensated when they are constrained
off the system. Instead it means a system where generators potentially
choose the extent of their access rights, and pay accordingly
through their transmission charges. For example, there are already
situations where wind farm generators have agreed contractual
arrangements with conventional power stations to share grid entry
capacity, with the latter providing back-up for the former when
the wind does not blow.[155]
The concept of sharing access was also a key part of the original
amendments to the CUSC put forward by National Grid in 2008 in
developing an enduring access regime.
94. Sharing network capacity has met with considerable
opposition because it would entail the removal of existing transmission
rights from incumbent generators.[156]
The Association of Electricity Producers (AEP) argued that generators
would have made investments on the basis of having secure transmission
access rights for the lifetime of a power station's operation,
and that this was what they paid Transmission Network Use of System
(TNUoS) charges for.[157]
In evidence, the AEP quoted a Chief Executive from the industry
who had said: "I simply cannot sign off the building of a
brand new power station to come into use occasionally to deal
with the variable supply of energy from renewables".[158]
Ofgem, in turn, have questioned the companies' assertion that
their access rights are guaranteed in perpetuity.[159]
Generators are liable only for one year's TNUoS charges at any
given time, and are free to reduce the amount of access they require
with only five days' notice to National Grid leaving consumers
to cover the cost of any assets stranded.[160]
The regulator concludes: "This lack of user commitment undermines
the efficiency of network investment, and will delay the connection
of new generation".[161]
Disagreement over this issue contributed to Ofgem's decision to
recommend the Secretary of State to intervene in the process.
95. One reason why generators are unwilling to
surrender their guaranteed grid entry is because the regulatory
framework distorts the relative cost of firm versus finite access
rights. With firm access, companies have the security of knowing
they will receive compensation if they are constrained off the
system, whereas non-firm access is comparatively expensive because
power stations do not know whether they will be able to export
to the grid. Under the existing regime there is little incentive
for generators to relinquish access capacity, even if they do
not make full use of it at all times. The key to solving the impasse,
as one witness noted, is to ensure that both options have efficient
costs attached to them so that generators' decisions on the level
of grid access they require reflects the costs they will incur
to the system.[162]
This may need to be combined with some kind of incentive mechanism
within the market that ensures a degree of spare generating capacity,
such as existed under the previous electricity trading arrangements,
known as the 'Pool'. This is because, at present, generators rely
on the receipt of constraint payments—which would be significantly
reduced if they did not have firm access to the network—to
cover some of their investment costs.
96. The second key feature of an enduring regime,
which is linked to the issue of access sharing, is the priority
of low-carbon technologies over conventional generation. The Association
of Electricity Producers argued that all forms of generation technology
should compete on a level playing field and network connection,
access and charging arrangements should be non-discriminatory,
cost-reflective and transparent.[163]
This would be more persuasive if the Government did not have a
clear strategic objective to decarbonise the electricity system.
Phil Baker and Dr Bridget Woodman at the University of Exeter
told us the replacement role of renewable generation suggests
that it should: "[…] be endowed with a natural priority
in terms of energy dispatch and also in accessing the electricity
system, thereby ensuring the maximum contribution to decarbonisation".[164]
97. The third key feature is the greater role
of demand in the access regime. We saw earlier in this Chapter
that the bulk of TNUoS charges are paid directly by consumers.
This imbalance in the apportionment of costs means a one megawatt
reduction in demand is treated differently by the charging regime
to a one megawatt increase in generation, despite the impact of
both actions on the system being the same.[165]
Furthermore the current DECC proposals for an enduring regime
exclude the demand-side from playing a greater role in the access
regime to alleviate constraints when they arise. We have seen
already that the greater role of active demand-side management
will be a vital part of a future smart grid.
98. Finally, several witnesses stated that an
enduring access regime, whatever form it takes, has to provide
long-term regulatory certainty to all market participants for
them to have the confidence to make investments. Scottish and
Southern Energy told us: "Stability and certainty in the
grid access and charging arrangements are essential to achieving
the EU 2020 target".[166]
E.ON UK also said: "Long-term regulatory certainty […]
is essential to give confidence to and ensure investment in the
network and generation with longer lead times, such as nuclear".[167]
Achieving this outcome would have to be balanced with the need
to develop a regime that also facilitated access sharing.
99. The old arrangements for
gaining access to the transmission network gave rise to a queue
of at least 60 GW of projects at various stages of development,
a large proportion of which are renewables, some of which have
potential connection dates as late as 2023. A new regime is vital
if the Government is to meet its targets for renewable energy
and emissions reductions. We welcome the 'interim connect and
manage' arrangements, which should facilitate the earlier connection
of 900 MW of renewable capacity in Scotland. We are, however,
concerned by the lack of progress in developing a long-term access
regime. It is extremely disappointing the industry has not been
able to agree reforms and the Government has had to intervene.
As far as possible, it is important an enduring regime is based
on consensus between all parties—the Government, the regulator
and the industry.
100. We believe that to facilitate
cost-effectively the formation of a smart grid and the delivery
of the Government's strategic objectives, a long-term regime must
contain four key features:
- Greater sharing
of network access, particularly between renewable and conventional
generators. This will reduce the need for investment in grid capacity,
and the likelihood of large constraint costs, although it may
need to be supported by additional market arrangements that guarantee
spare generating capacity on the system;
- Prioritisation of renewables
in electricity dispatch to maximise their contribution to decarbonising
the energy system;
- An equal role for the demand-side
in managing network access; and
- Arrangements that provide a
degree of stability and regulatory certainty for generators to
have the confidence to make investments.
We urge the Department to move quickly
to ensure an enduring regime is in place as early as possible
in 2010.
The industry's rule-making process
101. In November 2007 Ofgem announced its intention
to conduct a review of the various arrangements for governing
the industry's code and charging methodologies. The regulator
believes the existing governance procedures are not effective
at bringing about the coordinated and timely reform needed to
deliver the Government's climate change and security of supply
objectives—a view borne out by its recent experience in
attempting to implement an enduring transmission access regime.[168]
102. The Codes Governance Review, as it is known,
has a number of work streams on which Ofgem is currently consulting.
One set of proposals covering Major Policy Reviews would give
the regulator power to require network licence holders to implement
code modifications consistent with the conclusions of any such
reviews.[169] Although
changes would be subject to thorough consultation, this would
see a major reallocation of rule-making power away from the industry
to the regulator. The Chief Executive of Ofgem told us: "[…]
what we have to be able to stop going forward is the vested interests
within the sector, either filibustering or just straight blocking
reform […] we want as an organisation to be able to initiate
change".[170]
As a quid pro quo Ofgem has proposed that where code modifications
are likely to have only minimal impact on consumers or competition
the industry would be allowed to self-govern, rather than requiring
authority from the regulator. In a separate consultation, Ofgem
has also proposed opening up the procedures for modifying network
charges. At present, these are determined by the network owners—network
users, interested parties and consumers are not able to influence
how use-of-system or connection charges are determined. The regulator's
proposals seek to address this disparity. In both cases, Ofgem
expects to implement its reforms in 2010. It notes that any changes
to the governance procedures will not inhibit network companies
from seeking judicial review or a Competition Commission referral
with respect to any future changes to the industry codes or charging
methodologies by the regulator, which they see as unreasonable.
103. We welcome Ofgem's decision
to review the industry's rule-making process. The existing system,
under which only network owners can propose changes to the grid
codes and charging methodologies, has for far too long forestalled
reform in areas such as transmission access. The regulator's proposal
that it take powers to implement code amendments arising from
major policy reviews, whilst conceding power in areas of less
significance to consumers or competition, is a sensible approach.
So too is the proposal to make governance of the charging methodologies
more inclusive. Changes in both these areas will facilitate the
delivery of the Government's climate change and security of supply
objectives.
Developing offshore transmission
104. Britain has some of the best wind resources
in the world. It is for this reason the Government expects wind
power to be the main contributor in meeting our share of the EU
2020 target for renewable energy. A large proportion of this will
be built offshore, primarily in the North Sea, but also in the
Irish Sea.
105. Offshore wind development in British waters
began in 2000 with the Crown Estate's first round of leases for
13 locations. The first project under Round 1, North Hoyle, came
into operation in December 2003, and a number of projects have
followed since. In 2002 and 2003 the Crown Estate ran a second
licensing round, awarding 10 companies the rights to develop a
total of 15 sites in three strategic offshore areas. The estimated
potential generating capacity arising from Round 2 was between
5.4 and 7.2 GW.[171]
At present, nine offshore wind farms are operational with a combined
capacity of 688 MW. Another five schemes with a capacity of 1.1
GW are under construction.[172]
In January 2010 the Crown Estate announced the results of its
third licensing round, awarding contracts for development in nine
zones, which are much further out to sea, that could lead to 32
GW of offshore generation.[173]
In this section we look at the difficulties faced in connecting
offshore wind farms to the onshore network, and the Government
and Ofgem's framework for ensuring timely investment in offshore
transmission.
THE CHALLENGES
106. Delivery of the scale of generating capacity
anticipated in Round 3 will require substantial investment in
offshore networks. The Department estimates that investment worth
up to £15 billion is necessary over the next decade to connect
all three rounds of sites licensed so far.[174]
This equates to more than twice the asset value of the existing
onshore network. In addition, the large flows of electricity expected
from offshore wind farms will necessitate reinforcement in particular
parts of the onshore network. These investment needs formed part
of the Electricity Networks Strategy Group's (ENSG) recent analysis
discussed earlier in this Chapter.[175]
These works will need to progress in good time as the level of
offshore generating capacity connecting to the mainland grows.
107. Building networks offshore poses significant
technical and regulatory challenges. The construction of large
electrical power infrastructure in difficult offshore environments,
particularly for the Round 3 projects, has not been attempted
anywhere else on the same scale. The Institution of Engineering
and Technology (IET) told us: "the installation of rather
sophisticated electronic and other equipment offshore is new and
[…] something that will be pioneered in UK waters".[176]
Offshore transmission will use high-voltage direct current (HVDC)
as opposed to alternating current (AC) onshore because for undersea
cables it is cheaper and has lower losses. There will also be
operation and maintenance risks once the infrastructure is in
place. The harsh North Sea environment will mean turbines and
network connections are not always accessible. This will require
much higher levels of system reliability than onshore. The IET
argued the regulatory framework needs to recognise these risks.[177]
108. To manage electricity flows from offshore
the Department has extended National Grid's GB system operator
role. Accordingly, the company and the regulator have been working
to modify the various grid codes to take account of offshore transmission,
which is defined as 132 kV or above—the same as in Scotland—as
opposed to 275 kV or above onshore in England and Wales. Some
of our witnesses raised concern at the potential inequitable treatment
of offshore wind within the regulatory framework. Centrica highlighted
that offshore generators would not pay Transmission Network Use
of System (TNUoS) charges in the same way as onshore generators,
where the majority of costs are currently socialised across all
generators and consumers. Instead, the company notes that substation
and cable costs will be targeted directly at the offshore generator,
thus, it says, increasing their network costs by a factor of ten
or more.[178]
109. Prof Strbac pointed to further discrimination
in the regulations concerning the compensation generators receive
when the network is unavailable for them to input electricity.
Whereas onshore power stations are entitled to such compensation,
provided they comply with the network standards, this is not available
to similarly compliant offshore wind farms.[179]
On the grounds that both onshore and offshore network security
standards are based on the same principles, Prof Strbac saw no
justification for this differential treatment and thought it could
undermine seriously the financial viability of any offshore generators
that did experience difficulties with their transmission connections.[180]
In response National Grid argued that offshore wind farms would
have to meet lower connection and security standards than their
onshore counterparts and, therefore, could not expect the same
level of compensation.[181]
110. A further challenge for offshore networks
is in ensuring the supply chain is able to deliver the equipment
on time to connect new wind farms. The British Wind Energy Association
(BWEA) estimates that approximately 7,500 km of HVDC cable will
be required by 2020 to link up all the offshore projects planned.
Yet current global production of this cable is only around 1,000
km per year.[182] There
will also be demand for cabling as part of other countries' offshore
programmes, for example, Germany. The industry, therefore, believes
there is a major export opportunity for Britain developing domestic
cabling production. BWEA told us: "If the right signals
are sent to the cable companies, the resulting factories could
be sited in the UK, with benefits in terms of jobs and exports".[183]
The licensing regime will be a key determinant of the UK's attractiveness
as a place to invest.[184]
We discuss this in the next section.
111. There are many challenges
associated with the expansion of the electricity network offshore.
It is important the regulatory framework reflects these difficulties
and treats generators connecting offshore equitably vis-à-vis
their onshore counterparts. The offshore wind industry presents
a significant commercial opportunity for British industry, which
requires a regulatory regime that will stimulate domestic investment
in cabling and associated equipment manufacture.
THE LICENSING REGIME
112. The Department and the regulator have been
working together to develop the licensing regime for the developing
offshore transmission network. In the same way as for the onshore
network, licensed companies will be responsible for building,
owning and maintaining the offshore cables. However, rather than
the area-based monopolies currently enjoyed by the existing three
companies, licences will be awarded by tender as new offshore
generators seek connection. Offshore transmission owners (OFTOs)
will receive a 20-year regulated income stream from Ofgem and
generators will pay to use the cables through annual transmission
charges. These costs, along with those associated with the stranded
assets of any failed projects, will ultimately be borne by consumers.[185]
113. The first round of competitive tenders began
in summer 2009. In December Ofgem announced a shortlist of six
companies or consortia bidding for nine projects.[186]
The total value of the work is more than £1 billion and will
connect 2 GW of offshore wind capacity. The regulator expects
to announce the winning bids in May 2010. The first tenders to
appoint OFTOs will entail taking over the ownership and maintenance
of cables that are already under construction from developers.
Ofgem refers to these as transitional arrangements. In the future,
OFTOs will be appointed to design and build the grid connections
themselves, as well as own and maintain them. The regulator is
currently consulting on the enduring regulatory framework that
will govern these activities.[187]
114. Britain is not the first to use an auctioning
approach for new transmission wires—Argentina and Chile
have done so previously and successfully.[188]
However, it is the first to use auctioning for offshore connections.
Both the Department and Ofgem argued that there are various advantages
to their approach. First, they are keen to increase the number
of parties able to build the offshore connections and deliver
them quickly so as to minimise the risk of delaying new wind farms
coming on-stream.[189]
Second, they believe the auctions will create cost savings for
consumers, which the regulator predicts could total around £1
billion from all three offshore rounds. Third, the 20-year income
streams for OFTOs will, the Department argues, require less regulatory
oversight than the current five-yearly price control reviews.[190]
Finally, Ofgem hopes the competitive approach will also encourage
greater innovation.
115. Several of our witnesses supported the new
framework for licensing OFTOs.[191]
The Association of Electricity Producers told us: "the competitive
arrangements […] will deliver benefits in terms of lower
costs, more innovation, and getting more companies in to finance
these networks".[192]
Another witness noted that Britain will benefit from being one
of the first countries to adopt this approach, and will therefore
attract European and American companies that have not previously
been involved in the British market.[193]
This appears to have been borne out in the current auction where
only one of the six shortlisted bidders is an incumbent transmission
company—National Grid.
116. However, a number of witnesses also voiced
concern over the new licensing regime. The Energy Networks Association
highlighted the complexity of the arrangements, which ARUP argued
could undermine some of the expected benefits.[194]
Another risk is that the rules may prevent the exploitation of
synergies between different network concessions in the operation
of offshore generation and transmission assets.[195]
Also, the tendering for individual projects potentially reduces
the incentive for companies to invest in their capability to deliver
offshore connections because they will face uncertainty over whether
they will win future work.[196]
Moreover, with limited experience of the costs and risks of these
investments, combined with potential supply chain constraints,
companies may underestimate such factors and fail to deliver on
their bids.[197]
STRATEGIC INVESTMENT
117. The Department told us the majority of Round
1 and 2 projects will connect 'point to point'.[198]
This means each offshore wind farm will have its own transmission
cables that connect with the onshore network. Later Round 3 schemes,
though, are likely to follow a more zone-based approach whereby
a group of wind farms in a particular area, whether coming on-stream
simultaneously or phased over time, use a single link to connect
onshore. The Department believes this will ensure the development
of the offshore grid in a co-ordinated way.
118. Many of our witnesses argued the Government
and Ofgem's licensing framework failed to take a long-term strategic
view of the development of the offshore network.[199]
A particular concern was that 'point to point' connections would
result in the construction of radial transmission lines dedicated
to individual wind farms, leaving little scope for the later development
of an integrated offshore network that may connect together a
number of different projects in the future. Many believe this
will result in the construction of connections in a piecemeal
fashion and the evolution of a sub-optimal offshore network that
is more costly and less efficient. The Association of Electricity
Producers (AEP), for example, argued that the Government instead
needed to adopt a more holistic approach, ensuring the development
of connections for the first offshore wind farms was in line with
what would be required in the future when the much larger Round
3 schemes start to come on-stream—investment ahead of need
in the same way that Ofgem is implementing for the onshore network.[200]
Scottish Renewables argued too that such an approach would facilitate
the greater interconnection of the British and European electricity
networks.[201] As one
witness said: "A strategic and coordinated approach to offshore
subsea networks which link offshore renewables and also interconnect
with Europe will deliver a better solution in the long term".[202]
One approach suggested by the British Wind Energy Association
(BWEA) was for the appointment of a single OFTO for each of the
Round 3 zones. They would be responsible for connecting a number
of schemes in the same geographical area. This, BWEA argues, would
allow them to adopt a more coordinated approach, investing in
a transmission link to the onshore network early on that provided
efficient connection for later projects.[203]
119. In response to these criticisms Ofgem told
us the primary advantage of using 'point to point' links was that
they helped ensure the timely connection of new offshore wind
farms, which might otherwise be delayed if it adopted a more strategic
approach.[204] It noted
too that OFTOs' licences would include headroom of up to 20%,
allowing them to extend further their cable or develop a small
network within clusters of wind farms.[205]
Elsewhere, the Minister argued 'point to point' connections were
more cost-effective.[206]
The construction of even simple offshore infrastructure is expensive
and involves technical challenges. As one witness said, there
is "a simple technical and economic argument that tells you
to [use] 'point to point' for these sorts of amounts", referring
to the size of the current Round 1 and 2 schemes.[207]
Finally, the Chief Executive of the regulator also noted that
the asset bases of the transmission companies impacts upon their
stock market value. As such it was unsurprising they would oppose
the auctioning of offshore transmission licences whilst advocating
investment in network assets ahead of need.[208]
120. Connecting the first three
rounds of licences for offshore wind farms will require a capital
investment of £15 billion—twice the value of the existing
onshore transmission network. We therefore note the auctioning
approach for the delivery of future offshore transmission links
to ensure costs are minimised for the consumer. In the short to
medium term this will lead to the direct 'point-to-point' connection
of Round 1 and 2 wind farms as the most cost-effective and technically
feasible way forward, which also militates against the possibility
of delays. However, risks remain, particularly if companies underestimate
the cost of the work for which they have tendered. This means
the Department and Ofgem must keep its approach under review.
Moreover, it is not yet clear how the present framework will deliver
the most efficient network solution to connect the 33 GW of offshore
wind that is possible under Round 3. There remains a risk that
the current approach could lead to the piecemeal development of
the offshore network that is less cost-effective in the long run.
We note that the Department merely believes that zone-based approaches
to connecting wind farms onshore will develop. We do not consider
this is a sufficiently robust approach, and recommend the regulator
conducts more analysis to develop a route-map of how it expects
the competitive tendering regime to evolve to meet this long-term
challenge.
Interconnection
121. The anticipated expansion of wind generation
in Britain has led to greater discussion of the potential role
of interconnection in the energy system. This is the trading of
electricity between countries through grid connections known as
interconnectors. At present the GB system has two such links—one
with France and another with Northern Ireland. Under European
law, interconnectors may be funded as regulated assets, which
means consumers are exposed to the risks of their costs exceeding
the benefits. However, under certain conditions a merchant approach
is permitted that allows investor-led companies to build interconnectors
themselves.[209] At
present a number of projects are in development under the latter
method. A link with the Netherlands is under construction and
projects are at an advanced stage of planning for new links with
Belgium, Ireland and France. Proponents argue there are two main
benefits to greater interconnection—improved security of
supply and greater competition. In this section we consider each
of these in turn, as well as alternatives to interconnection.
We then assess the potential of the next generation of interconnection
in the form of a European 'super-grid'.
SECURITY OF SUPPLY
122. One of the main advantages of linking the
GB electricity grid to other markets is that interconnectors can
provide balancing services when there is either a shortage or
a surplus on the system. In so doing they can help ensure security
of supply. Most of our witnesses acknowledged the importance of
this role.[210] Interconnection
will also have a part to play in managing the impacts of intermittency
as the level of wind generation in Britain increases.[211]
Work conducted by the Centre for Sustainable Energy and Distributed
Generation (SEDG) suggests that wind curtailments on the GB system
may become material when the level of wind penetration exceeds
20%. This would be particularly prominent when low demand conditions
coincide with high wind outputs.[212]
Excess supply could also lead to within-day collapses in electricity
prices, and even negative prices.[213]
Such price volatility would undermine the investment case for
new generation capacity.[214]
However, many believe greater interconnection would allow wind
farms to maintain output, exporting surplus electricity to neighbouring
countries. In turn, during spells of low generation, the system
operator would potentially draw from reserve capacity in other
countries. Overall, this would reduce the need for domestic reserve
capacity and help ensure generating assets are used more efficiently,
thus reducing costs for consumers.[215]
123. Denmark, which has a high penetration of
wind generation, already uses this approach—interconnections
with Germany, Norway and Sweden allow it to export excess wind
power during periods of low demand and, at other times, draw on
the Nordic countries' vast hydroelectric resources. However, Denmark's
size in relation to its neighbours enables the management of output
fluctuations fairly easily. The balancing services the GB system
may require, if over a quarter of the electricity mix was wind,
would be an order of magnitude greater. This suggests it would
be difficult to manage wind intermittency even if there were a
number of interconnections. Moreover, as one witness noted: "weather
fronts are, in fact, bigger than countries".[216]
It is likely that when wind generation is high on the GB system,
the same will be true in neighbouring countries. This would reduce
the system operator's ability to export excess supply.[217]
124. Some witnesses questioned too the overall
value of interconnection as a means of securing electricity supplies.
Dr Michael Pollitt told us there is tentative evidence that greater
links between power control areas actually increases the risk
of multinational blackouts.[218]
This may be attributed to the additional complexity of system
operation over different jurisdictions, and the greater vulnerability
of an interconnected network to disturbances arising in other
countries.[219]
COMPETITION
125. Another potential outcome of more closely
linking the GB system with other countries is that consumers may
profit from greater competition in electricity supply.[220]
However, several of our witnesses were sceptical of any such benefits,
not least because four of the 'Big 6' energy suppliers in Britain
are already European companies. The Chemical Industries Association
noted: "The UK is effectively on the end of the European
network and there is a risk of gaming where pan-European suppliers
can make more profit by ensuring shortage of supplies to the UK".[221]
Ofgem too argued there is "the potential for exposure to
less competitive and less transparent markets".[222]
It pointed to current and past experience in Britain's interaction
with the European gas network, where there is a greater level
of interconnection. There the relative lack of liberalisation
on the Continent has arguably led to the British gas market acting
as 'lender of last resort' to the European system.[223]
Nor has interconnection for gas prevented large price spikes during
times of short supply. Dr Michael Pollitt told us that, given
the interaction of the gas and electricity markets in Britain,
improving the competitiveness of the European gas market might
prove a more cost-effective pursuit than trading electricity.[224]
DEMAND FLEXIBILITY AND FUEL SUBSTITUTION
126. Although interconnection has a role to play
in managing wind intermittency there are also other solutions.
In Chapter 2 we examined how greater flexibility and integration
of demand through smart grid technologies will be crucial in providing
balancing services across the network. Smart metering could also
facilitate greater fuel substitution where excess electricity
could be channelled into domestic water and space heating thermal
storage that would otherwise use gas.[225]
Denmark has recently begun to adopt a similar approach, preferring
to make use of its excess renewable generation to provide heating
rather than exporting it at very low prices. Prof Goran Strbac
told us the future energy storage capacity of the heating and
transport sectors, through the integration of demand and generation,
has a much greater potential to provide balancing services than
further interconnection.[226]
127. As the level of wind generation
in the electricity mix increases over the next decade, its intermittency
and unpredictability will make it increasingly difficult for the
system operator to balance supply and demand. A potential solution
may be greater interconnection with European networks. However,
the lack of progress in liberalising the European energy sector,
means Britain risks tying itself closer to markets that lack competition
and transparency, as has already happened, many would argue to
its detriment, in the gas sector. The Government should continue
its efforts to ensure the European Union makes rapid progress
on implementing full transparency of Member States' energy sectors
so that the UK is not further disadvantaged. In addition, it is
not yet clear to what extent the GB system would be able to rely
on other countries to provide balancing services, given weather
systems rarely conform to national boundaries. The regulator should,
therefore, proceed with caution in licensing future interconnection.
Moreover, the electrification of the transport and heating sectors
combined with active management of demand through smart grid technologies
could provide a means of managing wind intermittency in the future.
We believe it will be necessary to attain a clear view of the
cost/benefits of interconnection in the context of UK energy security
and the balancing of services, and recommend that Ofgem conducts
research to better establish this view.
THE 'SUPER-GRID'
128. In addition to the growth of interconnection,
the idea of a European 'super-grid' has gained recent attention.
This would connect European electricity markets with renewable
energy sources at the boundaries of the system, such as offshore
wind from the North Sea and Baltic Seas, hydropower from Scandinavia,
and in the long term, solar power from North Africa.[227]
Supply and demand would be linked through dedicated very high
voltage (HVDC) transmission lines. Various super-grid concepts
have been proposed over time. One, the Desertec Industrial Initiative,
launched in 2009, would see concentrating solar power systems
and wind farms located over 6,500 square miles of the Sahara Desert.
Requiring a substantial investment, it could provide up to 15%
of Europe's electricity needs by 2050.
129. The main advantages of the 'super-grid'
are similar to those for greater interconnection in terms of ensuring
security of supply and creating a pan-European market for electricity.
It could also make a significant contribution to European efforts
to decarbonise electricity generation, as well as having financial
benefits for the North African countries involved. However, there
would be a number of challenges. First, there are the technical
and engineering difficulties that such a project would entail.
The Institution of Engineering and Technology told us that whilst
these were surmountable in theory, it was still the case that
any such project would be the first of its kind so more work would
be necessary to establish feasibility.[228]
Linked to this is the skills capacity required to deliver such
a project. As the union Prospect told us: "This cannot simply
happen overnight and requires a whole set of engineering skill
sets in designing, specifying, planning, building, testing and
operating the network".[229]
A third concern is the regulatory challenge of harmonising grid
codes and standards across the various jurisdictions covered by
the 'super-grid'.[230]
Finally, timely delivery of the network assets may also prove
difficult, especially as the deployment of offshore wind in the
North Sea is already underway. The Department told us it would
not want to see the development of a super-grid delaying its plans
for offshore wind.[231]
130. Some witnesses raised questions about the
security of supply benefits that a super-grid would bring. Primary
among these are the geopolitical implications of being dependent
on North African states for a large proportion of our energy needs.[232]
The Institution of Engineering and Technology likened the potential
outcome to current concerns over European dependency on Russian
gas.[233] Moreover,
the Minister acknowledged: "cross-border pipelines in countries
where political stability is not always there does present a risk
[…]".[234]
Initial costs were also a significant concern.[235]
It was argued that the required outlay would displace domestic
investment in network and renewable generation infrastructure.[236]
131. To date, the Government has taken a cautious
approach in engaging with the super-grid proposals. The Department
told us it believed: "the costs and benefits […] relative
to the alternatives are not well-understood".[237]
The Minister said, however, that they were prepared to engage
on the issue and that DECC was part of a European Commission working
group looking at a potential North Sea project.[238]
The Government was also maintaining contact with its EU counterparts
on potential plans for a super-grid connection with North Africa.[239]
He noted too that the case for investing in the super-grid would
depend on its cost-effectiveness relative to other means of ensuring
security of supply, such as demand flexibility discussed above,
or more sophisticated energy efficiency measures.[240]
132. The 'super-grid' could
make a significant contribution to a low-carbon economy. However,
there are major technical and regulatory challenges, while the
necessary funding would likely require the redirecting of capital
from domestic investment in network and renewable energy infrastructure.
The super-grid would have some energy security benefits such as
reducing Britain's exposure to fossil fuel price volatility, but
would also bring with it new energy security risks, for example,
through a new energy dependency on North African countries. We
recommend the Government remains engaged at a European level in
exploring the super-grid's potential. Any future decision to invest
would require a robust analysis of the scheme's cost-effectiveness
relative to other means of securing electricity supplies, such
as greater demand flexibility.
53 Ev 232 (Scottish and Southern Energy) Back
54
Ibid. Back
55
Ev 103, para 4.2 (ABB), Ev 111, para 15 (Association of Electricity
Producers), Ev 149, para 33 (Department of Energy and Climate
Change), Ev 164 (Energy Networks Association), Ev 175, para 3.16
(E.ON), Ev 179, para 6 (ESBI International), Ev 212, para 3.1
(Ofgem), Ev 232 (Scottish and Southern Energy), and Ev 237 (Scottish
Chambers of Commerce) Back
56
Ev 111, para 15 (Association of Electricity Producers) Back
57
Ev 262, para 32 (Scottish Renewables) Back
58
Q 103 (Scottish Power) Back
59
Ev 237 (Scottish Chambers of Commerce) Back
60
Ev 179, para 6 (ESBI International) Back
61
Ev 232 (Scottish and Southern Energy) Back
62
Ev 252, para 9 (Scottish Natural Heritage) Back
63
Ev 120, para 10 (Campaign to Protect Rural England) Back
64
Ev 119, para 7 (Campaign to Protect Rural England) Back
65
Ev 149, para 33-35 (Department of Energy and Climate Change) Back
66
Department of Energy and Climate Change, Draft National Policy
Statement for Electricity Networks Infrastructure (EN-5),
November 2009 Back
67
For example, Ev 164 (Energy Networks Association) and Ev 203,
para 13 (National Grid) Back
68
Ev 175, para 3.16 (E.ON UK) Back
69
Ev 232 (Scottish and Southern Energy) Back
70
Ev 111, para 16 (Association of Electricity Producers) Back
71
Ev 227, para 9 (Renewable Energy Association) Back
72
Ev 149, para 29 (Department of Energy and Climate Change) Back
73
Q 154; Ev 227, para 9 (Renewable Energy Association) Back
74
Ev 131, para 33 (Centrica) Back
75
Ev 202, para 6 (National Grid) Back
76
For example, Ev 164 (Energy Networks Association), Ev 171 (Energy
Technologies Institute), Ev 227, para 11 (Renewable Energy Association),
Ev 258, para 7.3 (Scottish Power) and Ev 270 (Sussex Energy Group) Back
77
Q 3 (Prof Goran Strbac, Imperial College London) Back
78
Electricity Networks Strategy Group, Our electricity transmission
network: a vision for 2020, March 2009 Back
79
For example, Ev 110, para 11 (Association of Electricity Producers),
Ev 113, para 10 (Arup), Ev 129, para 9 (Centrica) and Ev 232 (Scottish
and Southern Energy), Back
80
Ev 174, para 3.6 (E.ON UK) Back
81
Ev 261, para 22 (Scottish Renewables) Back
82
Ofgem, Transmission Access Review-Enhanced Transmission Incentives:
Final Proposals, January 2010 Back
83
Q 307 (Ofgem) Back
84
Q 12 (Dr Michael Pollitt, Judge Business School, University of
Cambridge) Back
85
Ev 268, para 2.5 (Prof Goran Strbac, Imperial College London) Back
86
Ev 278 (P.E. Baker and Dr B. Woodman, University of Exeter) Back
87
Ibid. Back
88
Ev 267, para 1.6 (Prof Goran Strbac, Imperial College London) Back
89
Ev 264 (Prof Goran Strbac, Imperial College London) Back
90
Ev 278 (P.E. Baker and Dr B. Woodman, University of Exeter) Back
91
National Grid, Scottish Power, and Scottish and Southern Energy
Open Letter, A fundamental review of the Great Britain Security
and Quality of Supply Standard, 24 June 2008 Back
92
www.nationalgrid.com Back
93
Based on Ofgem, Addressing Market Power Concerns in the Electricity
Wholesale Sector-Initial Policy Proposals, para 1.28-9, March
2009 Back
94
Ofgem, Locational BSUoS Charging Methodology - GB ECM-18,
para 1.13, December 2009 Back
95
Ev 267, para 1.5 (Prof Goran Strbac, Imperial College London) Back
96
Ev 278 (P.E. Baker and Dr B. Woodman, University of Exeter) Back
97
Ev 264 (Prof Goran Strbac, Imperial College London) Back
98
Ofgem, Addressing Market Power Concerns in the Electricity
Wholesale Sector-Initial Policy Proposals, para 1.14, March
2009 Back
99
Ofgem Press Notice, Ofgem closes Competition Act 1998 case
against Scottish Power and Scottish and Southern Energy, 19
January 2009 Back
100
Ofgem, Addressing Market Power Concerns in the Electricity
Wholesale Sector-Initial Policy Proposals, para 1.15, March
2009 Back
101
Ibid. Back
102
Ofgem, Locational BSUoS Charging Methodology - GB ECM-18,
para 1.13, December 2009 Back
103
National Grid, GB ECM-18 Addendum, November 2009 Back
104
Ev 260 (Scottish Renewables) Back
105
Op. cit. Back
106
Q 88 (Scottish Power) Back
107
Ev 268, para 2.10 (Prof Goran Strbac, Imperial College London)
and Ev 278 (P.E. Baker and Dr B. Woodman, University of Exeter) Back
108
Ev 268 (Prof Goran Strbac, Imperial College London) Back
109
Ev 153 (Department of Energy and Climate Change) Back
110
Ev 202 (National Grid) Back
111
Ev 153 (Department of Energy and Climate Change) Back
112
Ev 217 (Ofgem) Back
113
Q 400 (Minister for Energy) Back
114
Qq 166 (Renewable Energy Association), 204 (Association of Electricity
Producers) and 282 (Institution of Engineering and Technology);
Ev 114, para 13 (ARUP), Ev 175, para 3.17 (E.ON UK) and Ev 180,
para 7 (ESBI) Back
115
Ev 223, para 12 (Prospect) Back
116
Q 163 (Scottish Renewables) Back
117
Ev 232 (Scottish and Southern Energy) Back
118
Q 90 (Scottish and Southern Energy) Back
119
Ev 262, para 39 (Scottish Renewables) Back
120
Q 63 (Dr Jim Watson, Sussex Energy Group) Back
121
National Grid, Conclusions Report: GB ECM-17, Transmission
charging-A new approach, September 2009 Back
122
Ev 217 (Ofgem) Back
123
Ev 264 (Prof Goran Strbac, Imperial College London) Back
124
Q 18 (Dr Michael Pollitt, Judge Business School, University of
Cambridge) Back
125
Q 166 (Renewable Energy Association) Back
126
Ev 153 (Department of Energy and Climate Change) Back
127
Q 317 (Ofgem) Back
128
Q 399 (Minister for Energy) Back
129
Q 165 (British Wind Energy Association) Back
130
Ev 264 (Prof Goran Strbac, Imperial College London) Back
131
Op.cit. Back
132
Ev 227, para 3 (Renewable Energy Association) Back
133
Ev 217 (Ofgem) Back
134
Ev 147, para 16 (Department of Energy and Climate Change) and
Ev 232 (Scottish and Southern Energy) Back
135
Ibid. Back
136
Ev 261, para 31 (Scottish Renewables) Back
137
Ibid. Back
138
Ev 261, para 32 (Scottish Renewables) Back
139
Ev 196, para 13 (Intergen) Back
140
Ev 232 (Scottish and Southern Energy) Back
141
Ev 148, para 18 (Department of Energy and Climate Change) and
Ev 212, para 3.3 (Ofgem) Back
142
Q 161 (Renewable Energy Association) Back
143
Ev 278 (P.E. Baker and Dr B. Woodman, University of Exeter) Back
144
Ofgem Press Notice, Ofgem speeds up connections for 450 megawatts
of low-carbon generation, 8 May 2009 Back
145
Q 158 (Scottish Renewables) Back
146
Ev 111, para 20 (Association of Electricity Producers), Ev 253,
para 15 (Scottish Natural Heritage) and Ev 262, para 34 (Scottish
Renewables) Back
147
Ev 131, para 30 (Centrica) Back
148
Ev 278 (P.E. Baker and Dr B. Woodman, University of Exeter) Back
149
Q 199 (Association of Electricity Producers); Ev 116 (British
Wind Energy Association) Back
150
Q 304 (Ofgem) Back
151
Ofgem Letter to the Rt Hon Ed Miliband MP, Transmission Access
Review - Third Progress Update, 25 June 2009 Back
152
Department of Energy and Climate Change, Improving Grid Access,
August 2009 Back
153
Ofgem, Response to DECC's Consultation on 'Improving Grid Access',
December 2009 Back
154
Ev 147, para 15 (Department of Energy and Climate Change) Back
155
Qq 17 (Prof Goran Strbac, Imperial College London) and 21 (Dr
Michael Pollitt, Judge Business School, University of Cambridge) Back
156
Ev 196, para 14 (Intergen) Back
157
Ev 111, para 22 (Association of Electricity Producers) Back
158
Q 208 (Association of Electricity Producers) Back
159
Q 314 (Ofgem) Back
160
Ev 217 (Ofgem) Back
161
Ibid. Back
162
Q 19 (Prof Goran Strbac, Imperial College London) Back
163
Ev 112, para 24 (Association of Electricity Producers) Back
164
Ev 278 (P.E. Baker and Dr B. Woodman, University of Exeter) Back
165
Ev 264 (Prof Goran Strbac, Imperial College London) Back
166
Ev 232 (Scottish and Southern Energy) Back
167
Ev 175, para 3.17 (E.ON UK) Back
168
Ofgem, Review of industry governance code-scope of the review,
June 2008 Back
169
Ofgem, Code Governance Review: Major Policy Reviews and Self-Governance-Initial
Proposals, July 2009 Back
170
Q 304 (Ofgem) Back
171
British Wind Energy Association Briefing Sheet, Offshore wind Back
172
www.bwea.com/statistics Back
173
The Crown Estate Press Notice, The Crown Estate announces Round
3 Offshore Wind Development Partners, 8 January 2009 Back
174
Ev 150, para 43 (Department of Energy and Climate Change) Back
175
Electricity Networks Strategy Group, Our Electricity Transmission
Network: A Vision for 2020, March 2009 Back
176
Q 285 (Institution of Engineering and Technology) Back
177
Ev 189, para 26.2 (Institution of Engineering and Technology) Back
178
Ev 132, para 38 (Centrica) Back
179
Ev 269, para 3.6 (Prof Goran Strbac, Imperial College London) Back
180
Q 38 (Prof Goran Strbac, Imperial College London) Back
181
Q 101 (National Grid) Back
182
Q 178 (British Wind Energy Association) Back
183
Ev 116 (British Wind Energy Association) Back
184
Ev 103, para 5.1 (ABB) and Ev 164 (Energy Networks Association) Back
185
Ev 150, para 40-42 (Department of Energy and Climate Change) Back
186
Ofgem Press Notice, Shortlist for over £1 billion of
offshore electricity links announced, 14 December 2009 Back
187
Ofgem, Offshore Electricity Transmission: Consultation on
the Enduring Regime, December 2009 Back
188
Ev 218 (Dr Michael Pollitt, Judge Business School, University
of Cambridge) Back
189
Op. cit. Back
190
Ofgem Press Notice, Shortlist of over £1 billion of offshore
electricity links announced, 14 December 2009 Back
191
For example, Ev 112, para 25 (Association of Electricity Producers),
Ev 116 (British Wind Energy Association) and Ev 131, para
35 (Centrica) Back
192
Q 212 (Association of Electricity Producers) Back
193
Q 29 (Dr Michael Pollitt, Judge Business School, University of
Cambridge) Back
194
Ev 114, para 16 (ARUP) and Ev 164 (Energy Networks Association) Back
195
Ev 208 (Nuclear Industry Association) Back
196
Ev 205, para 15 (National Grid) Back
197
Ev 114, para 17 (ARUP) Back
198
Ev 150, para 44 (Department of Energy and Climate Change) Back
199
Ev 103, para 5.3 (ABB), Ev 116 (British Wind Energy Association),
Ev 131, para 36 (Centrica), Ev 164 (Energy Networks Association),
Ev 189, para 25 (Institution of Engineering and Technology),
Ev 256, para 4.3 (Scottish Power), Ev 262, para 41 (Scottish Renewables),
Ev 271, para 10 (Sussex Energy Group) and Ev 278 (P.E. Baker and
Dr B. Woodman, University of Exeter) Back
200
Ev 112, para 26 (Association of Electricity Producers) Back
201
Ev 262, para 43 (Scottish Renewables) Back
202
Ev 103, para 5.3 (ABB) Back
203
Ev 116 (British Wind Energy Association) Back
204
Q 327 (Ofgem) Back
205
Ibid. Back
206
Q 411 (Minister for Energy) Back
207
Q 38 (Prof Goran Strbac, Imperial College London) Back
208
Q 330 (Ofgem) Back
209
Ev 214, para 5.3 (Ofgem) Back
210
Ev 103, para 6.1 (ABB), Ev 132, para 41 (Centrica), Ev 135, para
14 (Chemical Industries Association), Ev 151, para 50 (Department
of Energy and Climate Change), Ev 164 (Energy Networks Association),
Ev 176, para 3.20 (E.ON UK), Ev 205, para 19 (National Grid),
Ev 237 (Scottish Chambers of Commerce) and Ev 275 (Town and Country
Planning Association) Back
211
Ibid. and Ev 104, para 1.5 (Areva), Ev 112, para 28 (Association
of Electricity Producers), Ev 116 (British Wind Energy Association),
Ev 208 (Nuclear Industry Association), Ev 214, para 5.1 (Ofgem),
Ev 229, para 29 (Renewable Energy Association) and Ev 278 (P.E.
Baker and Dr B. Woodman, University of Exeter) Back
212
Centre for Sustainable Energy and Distributed Generation, Economic
and Environmental Impact of Dynamic Demand, November 2008 Back
213
Poyry, Impact of intermittency, July 2009 Back
214
Quoted by Ev 278 (P.E. Baker and Dr B. Woodman, University of
Exeter) Back
215
Ev 176, para 3.20 (E.ON UK) Back
216
Q 41 (Prof Goran Strbac, Imperial College London) Back
217
Ev 176, para 3.20 (E.ON UK) and Ev 278 (P.E. Baker and Dr B.
Woodman, University of Exeter) Back
218
Ev 218 (Dr Michael Pollitt, Judge Business School, University
of Cambridge) Back
219
Ev 105, para 5.2 (Areva) and Ev 114, para 20 (ARUP) Back
220
Ev 180, para 8 (ESBI) and Ev 205, para 18 (National Grid) Back
221
Ev 135, para 13 (Chemical Industries Association) Back
222
Ev 214, para 5.2 (Ofgem) Back
223
House of Commons Business and Enterprise Committee Eleventh Report
of Session 2007-08, Energy prices, fuel poverty and Ofgem,
July 2008, HC 293 Back
224
Ev 218 (Dr Michael Pollitt, Judge Business School, University
of Cambridge) Back
225
Ev 278 (P.E. Baker and Dr B. Woodman, University of Exeter) Back
226
Q 41 (Prof Goran Strbac, Imperial College London) Back
227
Ev 151, para 51 (Department of Energy and Climate Change) Back
228
Q 295 (Institution of Engineering and Technology) Back
229
Ev 223, para 13 (Prospect) Back
230
Ev 257, para 5.1 (Scottish Power) Back
231
Ev 151, para 53 (Department of Energy and Climate Change) Back
232
Q 41 (Dr Michael Pollitt, Judge Business School, University of
Cambridge) Back
233
Q 295 (Institution of Engineering and Technology) Back
234
Q 428 (Minster for Energy) Back
235
Q 39 (Dr Michael Pollitt, Judge Business School, University of
Cambridge); Ev 176, para 3.21 (E.ON UK) Back
236
Ev 182 (Helius Energy) Back
237
Ev 151, para 52 (Department of Energy and Climate Change) Back
238
Q 425 (Minister for Energy) Back
239
Ev 151, para 52 (Department of Energy and Climate Change) Back
240
Q 429 (Minister for Energy) Back
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