Memorandum submitted by University of
Exeter
Q1. What should the Government's vision be
for Britain's electricity networks, if it is to meet the EU 2020
renewables target and longer-term security of energy supply and
climate change goals?
The electricity sector is the largest producer
of greenhouse gas emissions and will be required to make a significant
contribution to the achievement of the UK's new renewable obligations
and longer term climate change goals. In order to deliver this
contribution, the Government needs to think beyond "electricity
networks" and develop a vision of a "sustainable energy
system" capable of accommodating the necessary renewable
and low-carbon generating capacity in the timescales required,
ensuring energy supply security through diversity of fuel use
and maintaining appropriate levels of supply reliability. Given
unprecedented uncertainties, for example the contribution of the
various energy sectors to climate change mitigation, the impact
of energy efficiency measures and nature of the future generation
portfolio, any vision of a sustainable energy system must, of
necessity, be high level. However, once a vision based around
a set of commonly agreed outcomes has been established, other
entities, for example Ofgem, could set about developing flexible
electricity market arrangements, networks and a regulatory regime
that would be consistent with the achievement of those outcomes.
Today's electricity system
The electricity system we see today has been
designed around large, flexible fossil-fired plant and inflexible
nuclear generation. Generation plant margins over demand have
historically been relatively modest at around 20-24%, reflecting
the controllability and high-availability of conventional generation
in meeting peak demands. The transmission network has essentially
been designed to accommodate the output of all generation simultaneously
to meet those peak demands and therefore exhibits relatively low
levels of congestion. Distribution networks have evolved to be
entirely passive in nature with little or no connected generation,
focussing on the delivery of energy from the transmission network
to individual consumers in a cost-effective and secure fashion.
Electricity trading occurs on a bilateral basis,
ignoring physical transmission system limitations and with the
costs of resolving any associated system congestion being "socialised",
ie spread across all users of the transmission system. Investment
requirements have been relatively predictable and are undertaken
on a centrally planned basis, using long-standing deterministic
security-based rules. Network regulation has historically reflected
this predictability, with investment requirements determined ex-anti
and with the regulatory focus very much on a very narrow view
of "economic efficiency" based on the concept of customer
commitment.
A sustainable electricity system
A truly "sustainable" electricity
system will have very different characteristics. It will need
to encourage the connection of sufficient renewable and low-carbon
generation to deliver the UK's renewable obligations and goals
and will be as close to being "decarbonised" as possible,
ie only using traditional conventional generation as a last resort
when insufficient renewable or low-carbon resource is available.
This "replacement" role implies that renewable generation
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.
The deployment of intermittent or variable-output
renewable generation technologies such as wind, tidal etc and
the need to retain conventional generation as "back up"
implies increased margins of generation capacity over demand and
the consequent need for available transmission to be "shared"
between renewable and conventional plant according to the availability
of renewable resource. This sharing of available transmission
capacity will result in potentially significant network congestion
and resolving that congestion will require efficient and cost-reflective
market mechanisms.
Transmission investment required to accommodate
numerous, often remotely connected, renewable generation projects
with relatively short development timescales will be significant,
but less predictable and more dynamic than has been the case to
date. The dependence on a narrow "customer commitment"
view of investment efficiency will no longer be appropriate and
a more strategic approach to investment will be required, taking
into account the UK's long-term sustainability objectives and
goals. Operating the electricity networks will become more complex,
with the need to manage shared transmission assets and volatile
power flows. Future regulation will need to recognise the increasing
uncertainties in operating and developing the electricity system
and focus on encouraging the maximum utilisation of available
network assets and objective trade-offs between investment and
operational alternatives.
Distribution networks will be required to host
increasing amounts of micro and smaller-scale renewable and low
carbon generation and become active in nature, with the operation
of distribution and generation resources being coordinated to
ensure network security. "Micro" or "smart"
grids will develop with aggregated generation and flexible demand
providing security services to the transmission system to replace
those previously provided by large centralised generation. Similarly,
and in addition to its role in facilitating bulk power transfers,
the transmission system will provide balancing services to these
actively-managed micro or smart grids.
Demand will also have a role in accommodating
variations in aggregated renewable output and in allowing additional
renewable capacity to be integrated into the electricity system.
Though increased exposure to real-time electricity prices via
intelligent meters, the use of "smart" appliances and
fuel substitution, electricity demand will have the capability
to respond to fluctuations in the availability of renewable resource.
Integration with the heat and transport sectors would allow electricity
demand to increase in response to price signals when renewable
resource is abundant and decrease when the availability of renewable
resource is reduced. In addition, the introduction of locational
electricity pricing would allow demand to respond to the presence
of network congestion and have a role in mitigating that congestion,
thereby reducing the need for transmission investment.
Q2. How do we ensure the regulatory framework
is flexible enough to cope with uncertainty over the future generation
mix?
Whereas today's networks of have essentially
developed to allow relatively predictable demand growth to be
supplied by large centralised generation, the future role and
development of networks is less certain. One scenario would be
that the required response to climate change would be based on
bulk renewable technologies such as wind and tidal, resulting
in the need for significantly more transmission capacity to handle
increased and volatile power transfers to load centres. Anther
plausible scenario might involved a reduced requirement for transmission,
with the development of "smart grids" accommodating
a growth in distributed and micro renewable technologies with
intelligent metering providing a flexible demand base. The most
probable outcome might lie somewhere between these two extremes,
however at this point the eventual contribution that might be
required from transmission and distribution is unclear.
Given these uncertainties and noting that, once committed,
network assets will be with us for in excess of 40 years, there
is a need develop a clear high-level vision of how the UK's environmental
and supply security goals might be achieved. As discussed above,
once a common view of the potential routes to achieving these
goals has been established, consistent and sufficiently flexible
regulation and market arrangements could be developed. Transmission
Owners (TOs) and National Grid as GB System Operator (GBSO), who
are best placed to determine future network requirements, could
be incentivised to embark on network developments in advance of
customer commitment, thereby addressing the mismatch between network
delivery timescales and the ability of individual renewable projects
to provide the necessary commitments. In addition, network access
arrangements could be amended to allow generation to connect in
advance of transmission reinforcement where necessary and practical.
In fact steps have been taken to achieve both these outcomes,
with Ofgem indicating that it is "minded to" extend
the BETTA transitional transmission access arrangements[128]
and with all the options for access reform being considered via
the Transmission Access Review (TAR) allowing generation the option
of connection in advance of network reinforcement.
The role of Ofgem in setting the framework for
energy investment needs to be reassessed: currently, the short
term interests of consumers are prioritised, while longer term
issues related to the strategic development of networks and the
delivery of sustainable systems up to 2050 and beyond is given
little or no consideration. Ofgem is an independent economic regulator
and although the exercise of its duties is to an extent defined
by Government guidance, it has considerable discretion to act
within a very broad framework. The framework should be narrowed
so that Ofgem can retain its independence but be required to act
within clearly defined parameters designed to ensure the delivery
of long term sustainable goals.
Q3. What are the technical, commercial and
regulatory barriers that need to be overcome to ensure sufficient
network capacity is in place to connect a large increase in onshore
renewables, particularly wind power, as well as new nuclear build
in the future? For example issues may include the use of locational
pricing, or the availability of skills.
Before addressing the issue of what needs to
be done to ensure that sufficient network capacity is in place
to allow the connection of the required renewable and nuclear
generation, some thought needs to be given to how we decide just
how much transmission capacity is required. While significant
network investment will clearly be necessary, the challenge of
delivering that investment in the timescales available together
with the potential impact on customer's electricity bills requires
that we ensure all investment is fully justified and efficient
in the context of the UK's long-term strategic goals. This will
require not only that the process for identifying the need for
additional network capacity is both objective, transparent and
consistent with these goals, but also that available network assets
are fully utilised.
Maximising the utilisation of available network assets
There is considerable redundancy in the transmission
networks and asset utilisation typically around 30%. While some
redundancy is necessary to ensure that demand can continue to
be supplied in the event of equipment failures and faults, there
appears to be considerable scope to increase asset utilisation.
Innovation and the deployment of emerging primary and control
technologies can clearly help in enhancing the capacity of the
existing infrastructure, however much can also be done by improving
operational procedures and techniques. An example of how a change
in operational procedures could enhance the capacity of the existing
transmission infrastructure would be a move to "weather-related
security standards".
Historically, the transmission system has been operated
to be secure in the event of the loss of two transmission circuits
strung on a single set of towers—a "double-circuit
fault". Such faults are quite rare but are more common in
poor weather, in fact some 70% of all transmission faults are
weather-related. Little or no account is currently taken of prevailing
weather conditions in operating the transmission system and it
would seem possible to relax operational security standards in
fair-weather conditions by, for example, covering the loss of
a single rather than a double circuit, without any appreciable
increase in risk to customer supplies. A "weather-related"
approach to security would significantly decrease the external
costs incurred in operating the transmission system and, as transmission
investment will increasingly be determined by cost-benefit analysis
as renewable deployment increases, would therefore reduce the
requirements for transmission investment.
Investment criteria
The criteria used to determine the need for
transmission investment were developed in the 1950s with the aim
of ensuring that the ability of conventional generation to contribute
to meeting winter peak electricity demand was not unduly restricted
by transmission capacity issues. The criteria are deterministic
in nature but with a cost-benefit "add on" to allow
additional investment to take place when economically justified.
Concerns have been raised over the treatment of intermittent generation
such as wind in the application of these criteria and the possibility
that the need for transmission investment might be overstated.
The basis of these concerns is the assumption that wind generation
has 60% of the capacity value of a conventional generator with
the same maximum output, whereas actual wind generation capacity
factors typically lie in the range 30-45%. Work undertaken by
the Centre for Sustainable Energy & Distributed Generation
(SEDG)[129]
confirms that capacity values of around 30-35% should be used
when carrying out cost benefit analysis to determine the need
for network investment.
The Balancing Mechanism, generation fixed costs and
market power
The divergence of view on what wind generation
capacity factor should be assumed when carrying out cost benefit
analysis to justify transmission investment primarily relates
to the cost of resolving transmission congestion via the BETTA
Balancing Mechanism. Due to the lack of any explicit reward for
generation capacity, generation displaced from the energy market
will attempt to recover fixed costs via the Balancing Mechanism.
This, together with possible exercise of market power[130]
by generators, results in the cost of resolving transmission congestion
via the Balancing Mechanism being significantly higher than was
the case with the Electricity Pool which preceded BETTA, or which
would be the case if Locational Marginal Pricing applied in the
UK. While the costs of resolving transmission congestion via the
Balancing Mechanism are often around £90/MWh or higher, fundamentals
suggest that costs of around £10/MWh should apply. Clearly,
much more transmission investment can be justified to avoid congestion
costs of £90/MWh than would be the case if the costs of congestion
were around £10/MWh and it is a real concern that more transmission
investment will be required to accommodate the UK's renewable
objectives with BETTA than would be the case if the old Electricity
Pool was still in place or if Locational Marginal Pricing were
to be introduced.
In addition to overstating the need for transmission,
the unnecessarily high costs of resolving network congestion has
the potential to discourage renewable generation from seeking
"early" connection to the transmission system, ie connection
in advance of any necessary network infrastructure reinforcement
being completed. Early connection will inevitably increase the
volume of transmission congestion and, depending on the outcome
of TAR, the costs of resolving that congestion will either be
smeared across all users of the transmission system ( a "connect
and manage" approach) or targeted on the generation responsible
for the increased congestion. In the event of connect and manage
forming the basis of an enduring transmission access regime, which
seems unlikely given a general lack of cost-reflectivity, the
fact that the resolution of network congestion is more expensive
that necessary is unlikely to have much impact of a generator's
desire to connect in advance of network reinforcement being completed.
However, the alternative options for access reform being considered
by TAR will either target the costs of resolving congestion on
the newly connecting generation or on all generation connected
to the non-compliant area of the transmission network. These targeted
costs could be significant and might be sufficient to make early
connection uneconomic for marginal renewable projects.
As suggested previously and leaving aside any
issues of market abuse, the fact the resolution of transmission
congestion via the Balancing Mechanism is more expensive than
with other market arrangements is linked to the recovery by generators
of their fixed costs. While it is appropriate for generation displaced
from the energy market to recover fixed costs when required to
operate via the Balancing Mechanism, it seems fundamentally incorrect
for generator fixed costs to be factored into the case for transmission
investment. As transmission is incapable of producing MW, additional
transmission capacity cannot replace generation, it can only allow
economic choices to be made as to which generation should be decommissioned.
Incentivising objective investment
Another concern in terms of ensuring objective
and efficient investment is the incentives flowing from the current
network regulatory regime. While developments in Transmission
Price Control (TPC) methodology over time have increased incentives
on TOs to undertake investment at least-cost, it is not clear
that the TPC and the GBSO incentive, in combination, provide sufficient
incentives to maximise the utilisation of existing transmission
assets and ensure that transmission investment is truly efficient,
either economically or strategically. Currently, the regulated
income that TOs are allowed to recover is a function of the value
of their asset base and there is therefore an incentive to grow
that asset base by building as much transmission as can be justified.
On the other hand, the GBSO incentive encourages NGET to outperform
an operational cost baseline set for the year in question and
is to all intents and purposes independent of Transmission Price
Control. Taken together, there is no overall mechanism which would
allow NGET or the Scottish TOs to benefit from forgoing investment
opportunities and associated long-term increase in revenues if
that decision resulted in a risk of an increase in system costs.
It is therefore concluded that transmission regulation
currently encourages investment over the adoption of operational
alternatives and that this is reflected in the TOs and GBSO taking
a cautious, low-risk, approach when making operational and investment
decisions. It is proposed that, given the transmission investment
challenges ahead and uncertainties over the disposition and timing
of renewable deployment, more attention needs to be given to the
minimisation of total network costs and ensuring that regulation
encourages objective trade-offs between investment and operational
alternatives.
Q4. What are the issues the Government and
regulator must address to establish a cost-effective offshore
transmission regime?
Offshore wind has a prominent role in the UK's
proposed Renewable Energy Strategy for 2020, and in the longer
term all marine renewables will presumably make a significant
contribution to the UK's electricity production if we are to deliver
a more sustainable system.
The current approach to devising a framework for
offshore transmission investment is at best confused and offshore
generators are not being treated in the same way as their onshore
counterparts. For example, offshore transmission is defined as
132kV and above, while onshore transmission in England and Wales
is 275kV and above.
In addition, unlike the onshore regime, the
construction and operation of new lines will be open to competitive
tender. Attempting to introduce elements of competition into the
construction and operation of new offshore networks will not necessarily
deliver substantial savings, but will ensure that the process
leading to the construction the new lines will be complex and
piecemeal. Current arrangements will lead to the construction
of radial transmission lines from the offshore wind farm, and
there is little scope for the development of offshore networks
to connect different projects and technologies in the future.
Overall the development of the offshore transmission
regime has been a lengthy affair with the final proposals appearing
to have been driven by an ideological commitment to competition
regardless of whether this would be appropriate in the circumstances.
Given the strategic importance of marine generating technologies
to the UK's electricity future, it would have been more appropriate
to continue either the current merchant approach to offshore networks,
or to give National Grid responsibility for constructing new transmission
lines under defined investment criteria. This would provide offshore
generators with some parity with onshore generation, while also
enabling a more strategic, long term view of the development of
offshore networks.
Q5. What are the benefits and risks associated
with greater interconnection with other countries, and the proposed
"supergrid"?
Increased interconnection with adjacent electricity
networks clearly has a role to play in allowing areas rich in
renewable resource to be developed beyond the point that would
be comfortable from a local or national perspective. An example
of interconnection allowing the increased deployment of renewable
capacity is West Denmark, which regularly exports surplus renewable
energy to Norway, Germany and Sweden. However, there may be limits
to the extent to which interconnection can be used to smooth variations
in renewable energy output. Weather systems often extend beyond
national boundaries and as the deployment of technologies such
as wind become more widespread, interconnection may become less
reliable as a means of exporting surplus renewable energy.
Denmark also provides an example of how demand flexibility
and fuel substitution can be utilised to absorb fluctuations in
the output of renewable energy. In December 2005, the Danish Parliament
legislated to allow electricity to be used for heating in district
heating schemes the large thermal storage capacity of these schemes
is now used to absorb surplus renewable energy. Switching from
gas to electricity during periods high renewable output has had
a pronounced effect in terms of stabilising electricity prices.
Studies by SEDG[131]
suggest that the need to curtail wind output during periods of
low electricity demand might first arise with an installed GB
wind capacity of around 16GW. As deployment increases beyond this
level, combinations of high wind output and the associated need
for spinning reserves to be held on conventional plant, together
with inflexible nuclear output will result in increasing instances
of wind curtailment. During these periods, electricity prices
can be expected to collapse or even go negative as wind generation
attempts to maintain access to ROC income. Clearly, low or negative
prices will damage the investment case for high capital-cost technologies
such as wind and nuclear.
The need for curtailment could be mitigated
by developing a diverse renewables portfolio or, as discussed,
by measures such as increasing interconnection with adjacent electricity
systems and encouraging fuel substation. Although, unlike Denmark,
the UK does not yet have a district heating infrastructure, access
to domestic water and space heating thermal storage could be achieved
by via smart metering and exposure to spot prices. Direct electrical
storage capacity could also be increased with the development
of pumped storage schemes, although potential sites are limited.
New, utility scale, storage technologies, such as compressed air
electrical storage (CAES) or flow-cell batteries could be developed,
while electric or hybrid vehicles could also eventually form part
of a distributed storage infrastructure.
Q6. What challenges will higher levels of
embedded and distributed generation create for Britain's electricity
networks?
The electricity network has evolved to transport
energy from the transmission system to individual customers and
has been designed on a "fit and forget" basis to be
independent of any connected generation. However, a sustainable
electricity system will consist of significant amounts of smaller
scale, distribution connected generation, which will require distribution
networks to move from their current passive configurations to
become more active participants in the electricity system. At
the moment, there are few incentives for distribution network
operators (DNOs) to invest in technologies which would allow their
networks to be more actively managed, and it is difficult within
the five year price control format for them to make a business
case for such investment.[132]
It should, however, be possible to provide incentives for DNOs
to invest in active management by, for example, allowing a greater
level of cost recovery from consumers.
Specific challenges will include the need to accommodate
the bi-directional power flows and increased fault levels that
will arise from the connection of distributed generation, manage
more volatile voltage profiles, more responsive demands and to
generally develop the control structures require to manage active
networks. As more generation connects, DNOs will be required to
develop a "system operator" capability in order to effectively
coordinate network and generation resources and to organise security
services to replace those previously provided by displaced transmission
connected generation. Furthermore, there may be a need for DNOs
to become involved in the contractual arrangements between the
GBSO and suppliers in order to recognise the interactions between
active distribution networks and the transmission system.
While these issues will change the operational
characteristics of Britain's electricity networks, they do not
pose any insuperable technical or security problems. Technologies
already exist to allow active network management, although there
are currently no real incentives for DNOs to invest in them.
Q7. What are the estimated costs of upgrading
our electricity networks, and how will these be met?
An initial assessment of the cost of connecting
the renewable generation capacity necessary to deliver the UK's
new renewable obligations together with new conventional generation
was given as around £12.6 billion by SKM in a report to BERR.[133]
More recent work carried out by the TOs for the ENSG,[134]
suggests that in addition to the £4 billion of investment
already authorised and excluding investment required to reinforce
the connections to the Western Isles, Orkney and Shetland, an
additional £4.7 billion of investment will be required by
2020. In other words, the investment needed to deliver our renewable
obligations and climate change goals could, in total, exceed the
regulated asset valve (RAV) of the transmission networks, which
currently stands at some £6.7 billion.[135]
When the need to extend and reinforce the transmission
networks is taken together with the need to refurbish and replace
existing assets that are nearing or have reached the end of their
useful life, it is clear that we have entered a period where capital
investment will dominate TO revenue requirements. Investment costs
will be recovered via Transmission Network Use of System (TNUoS)
charges applied to all users of the transmission system (ie generators,
suppliers and interconnector-owners) however; ultimately, the
costs of transmission investment will be borne by electricity
customers. With the cost of increased investment outweighing revenue
reductions accrued through efficiency savings, customers will
see the costs of providing a transmission service increase, reversing
the trend seen since privatisation.
It is clear that significant investment will
be needed in order to deliver our renewable and climate change
goals and to construct a sustainable system for the future. Furthermore,
there may well be a case for enhancing capacity ahead of need,
given that much of the UK's electricity infrastructure is in need
of upgrading or renewal. However, in order to protect the interests
of today's customers and ensure unnecessary costs are avoided,
it will be necessary for regulation to focus on ensuring not only
that investment is justified and efficiently carried out, but
that the utilisation of available transmission capacity is fully
utilised in the context of delivering those climate change and
sustainability goals.
Q9. How can the regulatory framework encourage
network operators to innovate, and what is the potential of smart
grid technologies?
At the last Distribution Price Control review
the negative impact of regulation on innovation was recognised
with the introduction of incentives to encourage innovation and
greater connection of distributed generation. These schemes—the
Innovation Funding Incentive (IFI) and Registered Power Zones
(RPZ)—have met with mixed success. While DNO funding for
R&D under the IFI has risen, comparatively little has been
spent on innovating for future active network management, rather
than for extending the life or refining the performance of existing
assets. Only a few RPZs have been proposed, despite early optimism
about the potential for the scheme. However, the intention behind
incentivising innovation and more active networks is good. The
schemes need to be maintained and revised to ensure that activities
geared towards more active networks and more connections of sustainable
generation are rewarded to a greater extent than activities designed
to maintain the current passive operation of distribution networks.
Q11. What can the UK learn from the experience
of other countries' management of their electricity networks?
The challenges associated with integrating renewables
generation into the electricity system are mostly generic in nature
and it should therefore be instructive to consider the policy
responses of other jurisdictions to those challenges, particularly
of those jurisdictions that have been rather more successful than
the UK in developing renewable capacity.
The principal challenges to integration relate to
the mismatch in the development timescales of renewable generation
and transmission infrastructure projects and the associated issues
of allowing early access to the electricity networks and managing
the resulting network congestion. As the deployment of renewable
technologies such as wind progresses, issues of managing intermittency
will also arise, as will the issue of dealing with surpluses in
renewable output and avoiding the need for curtailment.
Investment, early access and congestion
In terms of the mismatch between renewable project
and transmission infrastructure development timescales, it is
pertinent that both Germany and Denmark have adopted a rather
more strategic approach transmission infrastructure development,
encouraging pre-investment in order to open up areas of high renewable
resource. The German Energy Agency (DENA) for example has been
proactive in producing strategic electricity network studies linked
to the development of renewables, while legislation has been enacted
(the Infrastructure Acceleration Planning Law) which requires
utilities to provide anticipatory offshore transmission investment.
This strategic approach to infrastructure development is mirrored
in Denmark with the production of long-term infrastructure plans
linked to the delivery of energy policy objectives, resulting
in initiatives such as the interconnection of the Danish eastern
and western electricity networks.
These measures designed to ensure the timely delivery
of electricity infrastructure are complimented by, and are partly
as a result of, measures to allow the early access of renewable
energy to electricity markets and to manage resulting network
congestion. Both Germany and Denmark, in common with other jurisdictions,
have applied a "connect & manage" approach to connecting
renewable generation, which requires utilities to connect renewable
projects in advance of transmission infrastructure being delivered,
with renewable energy being guaranteed access to electricity markets
via "feed-in" tariffs. This approach has been successful
in delivering renewable capacity but, particularly in Germany,
has resulted in significant levels of network congestion. This
has been managed by restricting the output of conventional generation
(the whole point of deploying renewables) and also by curtailing
the output of wind when necessary.
With the Transmission Investment for Renewable
Generation (TIRG) report in 2004 and the more recent ENSG report
into the transmission development necessary to deliver our 2020
renewable obligations, the UK appears to be tentatively edging
towards a more strategic approach to infrastructure provision.
The outcome of the TIRG process allowed TO's to proceed with authorised
reinforcements safe in the knowledge that costs would be recovered.
However, Ofgem appear to be suggesting a different approach to
the work identified by the ENSG, with TO's being incentivised
to invest ahead of customer commitment by the prospect of an enhanced
rate of return on investments that ultimately become fully utilised.
Investment versus alternative means of increasing
network capacity
There may be sessions to be learnt from Norway
in terms of its approach to transmission infrastructure development.
Whereas countries such as Germany and Denmark have generally looked
to build new transmission assets in response to increasing network
congestion associated with the connection of renewables, Norway
has arguably taken a more objective approach to investment. For
example, Norway will always look to increasing the capability
of existing assets by thermal or voltage upgrades, or by other
means such as the use of interruptible transmission contracts
as a means of avoiding the need for new infrastructure. Whereas
it is clear that new transmission infrastructure will be required
in the UK to accommodate renewable generation, maximising the
utilisation of existing assets would seem to be a pre-requisite
for efficient investment.
Intermittency and curtailment
The fact that Germany and Denmark have installed
far more wind generation both in absolute terms and in relation
to the size of their electricity system(18% and 15% respectively)
than has the UK and have encountered few problems in terms of
intermittency, is reassuring. In fact there seems to be an almost
generally held view that the acceptable limit of installed intermittent
renewable generation is likely to be defined by economic rather
than technical factors.
One of these factors may well be the potential need
to curtail the output wind generation output during low demand.
This is an issue that been faced by Denmark in particular and
addressed primarily by exporting surplus output to Norway and
Germany. However, as renewable capacity builds in those countries,
relying on interconnection to manage energy surpluses will become
a less-viable option and Denmark has exploited fuel substitution
driven by exposure to real-time electricity prices to as a means
of mitigation. Denmark's experience holds valuable lessons for
the UK both in terms of the value of fuel substitution and the
fact that there is a limit to the extent to which national electricity
systems can rely on interconnection as a means of exporting energy
surpluses.
April 2009
128 Derogations to facilitate earlier connection of
generation-proposed interim approach. Ofgem, 19 March 2009. Back
129
Transmission Investment, Access and Pricing in Systems with Wind
Generation. SEDG February 2007. Back
130
Addressing Market Power Concerns in the Electricity Wholesale
Sector-Initial Policy Proposals (30/09. Ofgem, 30 March 2009. Back
131
Power and Energy Balancing in systems with nuclear and wind power.
SEDG. Back
132
EA Technology (2006), A Technical Review and Assessment of Active
Network Management Infrastructures and Practices, a report for
the ENSG, URN 06/1196, http://reporting.dti.gov.uk/cgi-bin/rr.cgi/http://www.dti.gov.uk/files/file30559.pdf?
nourl=www.dti.gov.uk/publications/pdflink/&pubpdfdload=06%2F1196 Back
133
Growth Scenarios for UK Renewables Generation and Implications
for Future Developments and Operation of Electricity Networks,
Report to BERR. SKM 2008b. Back
134
Electricity Networks Strategy Group (ENSG). Our Electricity Transmission
Network, a Vision for the Future. Report to DECC & Ofgem,
March 2009. Back
135
Transmission Access Review-Initial Consultation on Enhanced Transmission
Investment Incentives. Ofgem, 2008, 175/08. Back
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