Supplementary memorandum by the Office
of Gas and Electricity Markets (Ofgem)
1. The Committee heard oral evidence on
8 July 2008 from Ofgem's Chief Executive, Alistair Buchanan, and
Managing Director of Networks, Steve Smith. The Committee raised
several issues during the course of the session on which it was
suggested that Ofgem could provide additional advice and information.
Lessons from the Danish experience with renewables
2. Renewable energy currently constitutes
14% of total energy in Denmark and 28 per cent of electricity
generated.[3]
The UK Government's target is for renewables to contribute 15%
of Britain's total energy which equates to approximately 35-40%
of electricity generated.
3. The principal challenge that has faced
Denmark in accommodating such a large proportion of renewable
generation has been to manage the load variations associated with
intermittency. At night time and in summer they have often had
a surplus of wind generation. In order to balance the system,
therefore, they have been forced to sell this electricity to neighbouring
countries at very low or even negative prices. A similar challenge
could be faced in Britain where demand during night time and in
summer can fall to 30% of winter daytime peak levels. At the moment
it would be difficult for Britain to export large amounts of surplus
electricity because of our relatively smaller interconnector capacity.
However, a new interconnector to the Netherlands is under construction
and there are plans for new interconnectors to the Republic of
Ireland, Belgium and France.
4. One solution that has been tried in Denmark
is to put heating elements in Combined Heat and Power (CHP) boilers
so that they can be switched from gas to electricity, thus using
surplus wind power overnight and saving on high gas costs. While
this specific solution may not be as relevant to Britain where
we have a lower proportion of CHP, given time and investment it
could be possible to deploy similar solutions, for example using
immersion heaters in domestic heating systems. This would be likely
to take time and require smarter metering and control systems
to allow remote switching between gas and electric heating in
response to changes in prices that may occur over short time periods.
5. More generally, there are a range of
potential solutions involving suppliers offering new services
and tariffs to encourage customers to redistribute their demand
across the day. More use could be made of time-controlled domestic
appliances such as dishwashers and washing machines or more advanced
technologies that are able, for example, to reduce the load taken
by refrigerators and freezers whilst maintaining temperature in
response to prices. However, this too would require smarter metering
technology as well as dynamic demand control technologies.[4]
Requirements for reserve generation capacity
6. National Grid (NG) operates the electricity
transmission system in Britain and is responsible for forecasting
demand and ensuring that enough reserve capacity is available
to deal with sudden changes in demand or loss of generating capacity
over operational timescales (typically changes within the existing
half hourly balancing period). Generators and suppliers contract
with each other in the wholesale electricity market to meet this
demand and they notify NG of their contractual and physical positions.
NG can then signal to generators if additional capacity needs
to be brought on stream. In the event that generators' and suppliers'
contractual and physical positions are not in balance at any given
time, they incur imbalance or "cash out" charges that
are designed to reflect the costs incurred by NG in dealing with
any imbalance.
7. NG procures different types of reserve
services depending on their assessment of risk. Generally, NG
holds primary reserve (ie reserve that can respond within 2 seconds
for up to 30 seconds) large enough to cover the loss of the largest
single generating unit (currently Sizewell B at about 1.3GW).
Under its licence obligation it is required to hold enough reserve
for an event that can be reasonably expected.
8. Intermittent wind generators would contract
with suppliers in a similar way to other generators. They would
then predict their likely output, based on wind forecasts, and
would have two options to ensure that they have enough electricity
to meet their contractual obligations even when there is insufficient
wind for them to be able to generate. Firstly, they could contract
with other generators who would provide power when their wind
turbines are unavailable. (Many wind turbines are part of larger
generation portfolios so this process would be relatively straight
forward for them.) Alternatively, they could rely on NG to procure
reserve but accept that they would have to pay the costs that
NG incurs in procuring and using this reserve.
9. A new generation of nuclear power stations
would also have an impact on the amount of reserve capacity required.
It is likely that new nuclear power stations would be larger than
the existing ones, at around 1.6GW, and that NG may therefore
be required to hold more reserve capacity to insure against the
risk of the sudden loss of a nuclear power station. This may not
solely be an issue for new nuclear power stations as some of the
planned offshore wind farms could all feed into a single line
connecting to the onshore grid and be of a similar size. This
would also require NG to hold more reserve. NG have estimated
on the basis of current market prices that the costs of additional
reserve necessary to secure the system against the loss of the
larger nuclear designs (or similar sized offshore connections
for offshore wind) could be of the order of £100 million
per annum to make sure they could maintain system frequency if
a larger nuclear station (or offshore renewable connection) became
suddenly unavailable over operational timescales—as happened
recently on 27 May. These additional reserve costs would not increase
proportionately for every large new nuclear station added to the
system as the probability of losing two large nuclear stations
is much lower than the probability of losing a single station.
NG would therefore assess the cost of procuring reserve against
the level of risk.
10. We have stated that NG would need to
consult on a cost reflective methodology to target the recovery
of any additional reserve costs, wherever possible, at those generators
which are causing them to be incurred. This should ensure that
the arrangements do not favour any particular technology but instead
seek to target any additional network and balancing/reserve costs
on those generators who cause them. It would simply extend the
existing principles that apply to the recovery of transmission
infrastructure costs and balancing and reserve costs.
11. In the longer term, the challenges associated
with intermittency can be met through a range of established and
emerging technologies combined with behavioural changes. Intermittent
generation requires back up, for example when the wind is not
blowing, and this could be provided by pumped storage and open
cycle gas turbines as well as coal and gas stations (with or without
Carbon Capture and Storage). However, as the proportion of wind
energy increases, the back-up generation becomes correspondingly
more expensive as it sits idle for much of the year. Emerging
technologies including batteries and fuel cells could become economically
viable if their costs continue to fall or if the volatility of
electricity prices rise. Finally, behavioural and technological
changes can help by managing demand in response to intermittency.
For example, smart meters, time of day pricing and new technologies
that control domestic and industrial appliances—such as
shutting down fridge motors—can be used to manage demand
in response to intermittency. However, all of this costs money
and takes time.
The role of Ofgem in helping to meet the target
12. Ofgem has clear plans and timetables
to ensure that there are no barriers arising from electricity
and gas regulation to meeting the Government's renewable energy
target.
13. For example, we have three main areas
for action to improve access to the electricity transmission grid.
First, new transmission access arrangements from April 2010 will
enable better use of existing grid capacity (eg through sharing
and trading), faster connections and better information to National
Grid about future demand—all of which will contribute to
better investment planning. Second, we are introducing short term
measures to allow renewable generators to connect to the grid
in the next two years, before the new enduring access arrangements
come in, if they are able to accelerate their plans. Third, we
aim to have in place new investment incentives on the network
companies within the next 12 months which will protect consumers
by encouraging grid companies' shareholders to take on more of
the risk when they seek to invest. More information on this work
can be found in paragraphs 27-43 of our initial memorandum.
14. All this is in addition to Ofgem's existing
work through our price controls. We are allowing a 160% increase
in investment in the onshore electricity grid between 2007 and
2012. This is to upgrade the wires and connect new generation,
much of it from renewable sources. The funding is flexible and
can increase automatically if more generation seeks connection
than was assumed when the price control was originally set.
15. We also have workstreams addressing
the issues for smaller generators, covering distributed energy,
microgeneration and the role of the electricity distribution networks.
We are advising Government on design of policy in relation to
heat and energy efficiency.
Could the costs become excessive?
16. Members were interested to understand
the circumstances in which the cost of promoting renewables could
be excessive.
17. The cost of promoting renewable electricity
generation will depend on a number of factors including the level
of any target, the robustness and efficiency of the policy measures,
the resource costs of the technologies and their evolution over
time, and the impact on system security and balancing costs.
18. One scenario could be if the subsidy
mechanism to meet a renewable energy target is poorly designed
and has unintended consequences. For example, when the existing
Renewables Obligation was designed, few in the industry would
have anticipated the large increases in wholesale electricity
prices that have occurred since 2003 or the introduction of a
carbon price through the European Emissions Trading Scheme. As
a result, the level of subsidy for some forms of renewables has
exceeded the amount needed to make them viable. This problem could
be addressed by Ofgem's suggestion of linking the level of subsidy
inversely to the wholesale electricity price.
19. A second scenario could be if insufficient
attention is paid to other more effective and efficient ways to
achieve green house gas emission reductions. These means could
include other low carbon generation technologies, energy efficiency,
emissions trading and renewable heat—as well as renewable
electricity. At present, for example, there is considerable uncertainty
about the future costs of different renewable energy technologies.
The main rationale for supporting renewables at greater cost than
the shadow price of carbon is to develop the technology so that
costs fall. Generally, the best way to ensure that the costs incurred
do not exceed the level necessary is not to support particular
technologies but to put in place broad-based policy instruments
which allow the market to find the most cost-effective way of
reaching the overall objective of reducing carbon.
20. A third scenario whereby costs may be
excessive would be if there was no locational signal in transmission
charging and most new renewable generation chose to locate in
the most difficult areas for the network to accommodate at significant
cost and with potential environmental damage if there were other,
low carbon generation technologies that could be located closer
to demand reducing the economic and environmental cost of a much
larger grid. This is discussed further below.
Locational transmission charging
21. The further a source of energy is from
its end user, the more it generally costs to transmit. Generators
who are sited closer to the main centres of demand therefore pay
lower network charges than those who are further away.
22. The approach of locational charging
has two main benefits. First, it is equitable because the charges
to generators reflect the costs they are imposing on the grid.
Second, it encourages generators to make efficient decisions about
where to locate. This helps to reduce costs to customers and cut
carbon emissions. To see how this works in practice one can look
at the example of the north of Scotland. This largely rural area
is far away from the main sources of demand for electricity in
Britain. Generators who choose to locate in the north of Scotland
therefore pay higher network charges to reflect the associated
costs of transmitting it to the main urban centres. Scottish customers,
on the other hand, pay substantially lower network charges than
in the south of England, because they live nearer to the electricity
and it does not have to travel as far to reach them.
23. Critics of the current approach tend
to come from one of two perspectives. Some argue that the locational
charges do not vary enough and that there should be an even stronger
economic signal to generators to site their plant closer to demand.
For example, Professor Andrew Bain argued in his written evidence
that there should be an additional locational charge to take into
account the cost of the electricity lost as it travels down the
transmission wires. At present, all generators pay equally based
on the average cost of electricity lost on the whole transmission
system rather than for their specific loss factor, which can vary
significantly at different locations on the network. We are sympathetic
to Professor Bain's argument and for over 15 years we have supported
proposals to change the industry rules in order to introduce locational
charging for transmission losses. However, some generators have
vigorously opposed the proposals and have subjected them to judicial
review three times—most recently winning a challenge in
June this year. We have continued to indicate our support for
the principle of locational transmission losses charges but there
are currently no such proposals on the table. Under the current
industry rules, Ofgem does not have the right to initiate such
proposals and so they must come from the industry itself.
24. Others argue that the current approach
unfairly penalises Scottish generators by making them pay higher
charges (even though Scottish customers benefit by paying lower
charges). We do not think that this argument is convincing. The
introduction of locational charging has not proved to be a disincentive
to renewable generation in Scotland, and the major barriers to
renewables are in fact planning delays and the time needed to
build transmission connections.
25. Before locational charging was introduced,
Scottish generators had to pay a number of separate fees for accessing
the network and transmitting their power. These fees have now
been replaced by a single locational transmission charge, thus
making the system much simpler. Second, locational charging does
not harm the viability of renewables in Scotland given the support
these schemes receive through the Renewables Obligation. In fact,
since the launch of the Britain-wide electricity market in 2005,
a queue has built up in Scotland of around 165 renewable projects
awaiting connection—significantly more than is needed to
meet the Scottish Government's renewable energy targets. This
evidence is in line with the conclusions of two sets of consultants
hired by the Government to assess the economic case for using
the power under section 185 of the Energy Act 2004 to cap transmission
charges for renewables in remote parts of Scotland. The consultants
concluded that even with locational transmission charges a 250MW
windfarm on the Orkney Islands could earn a rate of return of
nearly 40% based on the current level of support offered by the
RO scheme. Both sets of consultants concluded that using the powers
would not be necessary to make wind projects in Orkney and Shetland
viable, and that there was only a marginal economic case for using
the powers in respect of the Western Isles.[5]
26. We hope this information is useful to
the Committee and we would be happy to provide any further assistance
that you may require.
Steve Smith
Managing Director of Networks
1 August 2008
3 Danish Energy Authority Back
4
Dynamic demand control devices can either be built into appliances
or be attached to appliances and communicate with a smart meter
to change their electric demand dynamically according to the conditions
on the grid and/or movements in energy prices. Back
5
http://www.berr.gov.uk/files/file46776.pdf Back
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