Submission from Sustainable Development
The Science and Technology Select Committee
(STSC) in conducting a wide-ranging inquiry on Renewable Energy-Generation
Technologies. This is the Sustainable Development Commission's
(SDC) response to the call for evidence.
We have focussed on two renewable technologies
(wind and tidal) and on the role of intelligent grid management
in supporting the development of renewable technologies. This
draws on our previous work on wind energy
and our current work on the role of Ofgem,
and on tidal power,
both due to be published in autumn 2007.
Onshore wind is the most commercialised renewable
technology today. It is one of the more competitive renewable
generating technologies and as such has been the technology most
supported by the Renewables Obligation (RO).
The connection of offshore wind projects represents
the next stage of UK renewables deployment with projects starting
in Robin Rigg (180MW), Lynn (90MW), Inner Dowsing (90MW), and
Gunfleet Sands (180MW) all of which are being supported by the
Offshore Wind Demonstration Programme.
Deployment and timescales
There is currently around 2GW of wind generation
connected to the UK's electricity generating system, with a further
1,260MW of renewables under construction; there is also 4,600MW
with consent and 11,4000 MW in the planning process.
The main barrier to further deployment is the
multiple delays in granting planning permission for both individual
wind development projects and for the transmission and distribution
infrastructure required to connect renewable generators to the
The grid infrastructure in the North of England
and Scotland is currently congested with little spare capacity
for the connection of new projects. Under the current Security
and Quality of Supply Standards (SQSS) the capacity of all generating
stations cannot exceed the capacity of the grid infrastructure.
This means that the capacity of the network needs to be increased
before new projects can connect.
The upgrade of the Beauly-Denny line to 400kV
would increase the capacity of the network in Scotland by around
6GW and would allow for the connection of 67 new renewable projects.
However the upgrade of the line will have an impact on visual
amenity in areas of Scotland and as a result is currently subject
to public inquiry, which could delay construction until 2012.
It may also be subject to under-grounding requirements.
An influx of renewable applications prior to
the introduction of the British Electricity Transmission and Trading
Arrangements (BETTA) along with existing capacity constraints
has lead to a queue of projects (known as the GB or BETTA queue)
awaiting connection to the transmission and distribution system
in Scotland. This queue is managed on a first-come first-served
basis which has led to a situation where some of the projects
at the front of the queue which do not have planning consent or
appropriate financial backing are delaying the connection dates
for other projects which are more likely to go ahead. One alternative
approach would be to move to a "connect then manage"
approach, which would see renewable generation connected so that
the capacity of the grid was exceeded, but accounted for by a
reduction in the generating output of fossil fuelled plant.
These challenges apply to both onshore and offshore
wind. However, for offshore wind the absence of a firm offshore
regulatory framework adds additional risk. At present there is
no agreed framework for how offshore wind should connect to the
transmission system and how the commercial relationship between
projects and grid operators should work. Government and Ofgem
have recently agreed part of the offshore regulatory regime, and
this will allow the construction of offshore lines to be open
to competitive tendering between transmission companies and other
interested parties. This is important progress in finalising the
offshore regulatory regime by 2008. However, the process so far
has been characterised by decision-making delays in the Department
for Business, Enterprise and Regulatory Reform (formerly Department
for Trade and Industry) which need to be avoided in future if
the 2008 deadline is to be met.
In our 2005 report on wind power, we estimated
that the generation costs of onshore wind power to be around 3.2p/kWh
(+/-0.3p/kWh), with offshore at around 5.5p/kWh, compared to a
wholesale price of around 3p/kWh.
The additional system cost was estimated to be around 0.17p/kWh
when wind makes up 20% of total capacity installed. This figure
accounts for the additional costs caused by the variability of
wind, which requires a small increase in "balancing requirements"
of the network operator. Generation costs are likely to decrease
over time as the technology improves, but this will be balanced
against increased costs for integrating higher levels of wind
generation into the system. However, as the SDC's work, and the
more recent work by the UK Energy Research Centre (UKERC),
has shown, wind power and other "intermittent" generators
do not require dedicated backup capacity, and the cost of handling
any net increase in variability is small.
The generation costs of offshore wind are harder
to calculate, and are proving to be more expensive than anticipated.
In its current form the Renewables Obligation will not deliver
sufficient financial support to for large-scale deployment of
offshore wind, but the recent decision to band the RO should change
Wind is free and uncontrollable which means
that the marginal operating cost for wind generation is close
to zero. Wind generation would rather sell its output than not.
This essentially means that wind will take the lowest wholesale
price which is often set by the price of gas. As such the financial
return on wind generation is variable and dependent on the wholesale
price of electricity.
Under the British Electricity Trading and Transmission
Arrangements (BETTA) around 2% of the electricity traded is done
so through the balancing and settlement mechanism. The mechanism
was designed to incentivise parties to match supply with demand
and encourage investment in generation to minimise the risk of
large-scale power outages. This was achieved by having two imbalance
prices, a System Buy Price and System Sell Price.
Through this mechanism generators have to state
how much electricity they will generate every half hour. Generators
that under-produce must buy electricity at the system buy price,
those that overproduce must sell the surplus at the system sell
price. Whilst the predictability of wind and other intermittent
generators does improve over a half hour period there is still
greater scope for being out of balance and paying punitive charges.
The costs of the mechanism are very high for
small generators, such as renewables, who are exposed to risk
from the spread between the two imbalance prices. However, renewable
generation has to reach a significant proportion of the total
GB generating mix to pose a significant risk to the balance of
supply and demand.
Ofgem recently approved a code modification
(P197) which changed the basis for system buy and sell prices
to reflect the marginal price of electricity, thereby increasing
the cost borne by the generator for being out of balance. This
has led to a situation where the generators that are being most
heavily penalised are the ones that pose the least risk to the
Whilst the RO allows wind to cover the cost
of the balancing mechanism, it's existence is evidence of a set
of trading arrangements which do not recognise the particular
characteristics of wind or other renewable generation.
The energy balance, or "carbon payback",
of wind turbines has been cited as a factor that limits its effectiveness
at reducing greenhouse gas emissions. There are a number of studies
on this subject
with most suggesting that wind turbines take between three to
10 months to produce the electricity consumed during their life-cycle.
The payback period varies depending on the size of the project
and the location.
The SDC is currently conducting a review of
the potential for tidal power in the UK, with funding support
from the UK Government, Welsh Assembly Government, Scottish Executive,
Department of Enterprise, Trade and Investment (Northern Ireland),
and the South West Regional Development Agency. The project was
originally announced in the DTI's Energy Review,
and was restated in the Energy White Paper 2007.125 The review
covers both types of tidal resource, tidal stream and tidal range,
and reviews the technologies available for harnessing this resource.
The SDC is assessing the potential role of tidal
power generally, and of a Severn barrage specifically, to contribute
to the twin challenges of climate change and energy security.
The primary aim of the project is to develop a public-facing report
on tidal power in the UK from a sustainable development perspective
which will include recommendations for policy-makers. The SDC's
work is based on a set of evidence-based research reports looking
at the various issues in more detail, along with the results of
a substantial public and stakeholder engagement programme.
Our review has been confined to an assessment
of existing studies and research; it has not involved any new
primary research except where this has been provided to the SDC
directly. Our review of options for a Severn barrage has focussed
on two principal barrage options: the large Cardiff-Weston barrage
promoted by the Severn Tidal Power Group (STPG) and the smaller
Shoots barrage close to the second Severn crossing and currently
promoted by PB Power. The review recognises that there are other
schemes which have been studied previously or are currently being
suggested, for example, Somerset County Council's interest in
an outer barrage to address flood protection objectives, and these
schemes will be referenced but are not considered in detail. The
report will also address tidal lagoons and tidal stream technologies
from a UK-wide perspective.
We hope to publish our final report and the
accompanying evidence base in Autumn 2007.
There is an increasing need for the development
of more sophisticated grid management solutions in order to facilitate
the connection of renewable and low carbon generation.
The current energy system is based around a
series of large power stations connected to the transmission network.
The transmission system operator's role is to ensure that supply
and demand of energy are always in balance so as to ensure that
the lights stay on. The distribution network operators (DNO) in
the current system are designed to be only passive players in
the energy system, ensuring that electricity flows from the transmission
network to our homes and businesses.
However, as the market moves towards increasing
levels of distributed generation so it will be important for the
distribution networks to become more active managers of the energy
flowing across their network. As the distribution networks become
more active, so the system can start to provide more innovative
solutions for matching the characteristics of different types
of generation with different demand profiles.
Deployment and timescales
Ofgem have recognised the potential for intelligent
grid management and put in place a series of incentives to move
the distribution networks to become more active in managing energy
flows. However, a move to more active management of the distribution
networks could be costly, and the need depends largely on whether
distributed generation technologies can compete in the current
The DNOs have an incentive to connect distributed
generation, which in 2005 was set at the rate of £1.50 per
MW of connected distributed generation. This incentive is reinforced
by the Registered Power Zones programme which provides an extra
£3 per MW if the connection is made using an innovative solution.
However, the incentive is having little impact as the criteria
for receiving the it is quite narrow and, once demonstrated, the
innovative solution can no longer gain the additional funding
when used by other DNOs. This has led to the demonstration of
innovative solutions but no mechanism for the rapid commercialised
Work being done by Surrey University in association
with United Utilities
highlights the potential for DNOs to lose money by connecting
distributed generation. This is due to the loss of revenue that
would have come from the charges associated with the pass-through
of electricity from the transmission network. Whilst this work
is still at an early stage, it potentially highlights the need
for a more thorough review of the charging and incentive arrangements
for DNOs, to facilitate the move towards more active management.
At present, the innovation spend by DNOs is
very low, with the highest (EdF) at around 0.4% of turnover. The
UK all-industry average for innovation expenditure is around 2%
of turnover. Ofgem adopted an innovation funding incentive in
the 2005 price control review which allowed DNOs to spend 0.5%
of their turnover on innovation. This has helped to restore innovation
funding to levels equivalent to pre-privatisation, but is still
below the UK national average for all industries.
Timing is a critical issue. Network assets have
a long lifetime, with investments made over the next five to 10
years delivering infrastructure that will last until 2050. However,
the low level of innovation means that network expenditure is
going on like-for-like replacement of network assets, meaning
that the grid in 2050 will be no more technologically advanced
than the grid of 1970. A much stronger focus is required on the
incentive regimes for network innovation to reduce network losses,
increase capacity and ensure that the system is future-proofed
for the connection of new generating technologies.
119 SDC (2005). Wind power in the UK. http://www.sd-commission.org.uk/publications.php?id=234 Back
Further details can be found on the SDC website at http://www.sd-commission.org.uk/pages/ofgemreview.html Back
Further details can be found on the SDC website at http://www.sd-commission.org.uk/pages/tidal.html Back
Figures obtained from the British Wind Energy Association website:
These prices are based on pre-2005 data and are therefore likely
to have changed. Back
UKERC (2006). The Costs and Impacts of Intermittency.
HM Government (2007). Meeting the Energy Challenge. Energy
White Paper 2007. http://www.dti.gov.uk/energy/whitepaper/page39534.html Back
Danish Wind Turbine Manufactureres Association (1997), The Energy
Balance of Modern Wind Turbines, Available from http://www.winpower.org/en/tour/env/enpaybk.htm;
citations in Wind Power Weekly (1992), Available at http://www.awea.org/faq/bal.html;
and Milborrow, D, (1998), Dispelling the Myths of Energy Payback
Time, Wind Stats Newsletter, Vol 11, No 2. Back
HM Government (2006). The Energy Challenge. Energy Review
Report 2006. http://www.dti.gov.uk/energy/review/page31995.html Back
University of Surrey/Unied Utilities a tool to analyse the regulatory
incentives on a distribution network operator at a project level