extracts from the consultation
Our electricity market has served us well, providing affordable and secure energy
since the 1990s.
The watchword has been the encouragement of competition
overseen by Ofgem as the independent regulator of the sector. As a result we have
had some of the lowest electricity prices in the EU and this model formed the basis
for EU rules on energy markets and independent regulation.
However, in the
coming decades we face major new challenges which require careful but farreaching
reforms to meet our objective of ensuring the supply of reliable, lowcarbon
and affordable electricity:
Even as we improve energy efficiency, demand for electricity may need to
double by 2050 – as decarbonisation of the economy means that electricity
provides more of our heating and transport needs;
To ensure security of supply, we will need to replace a quarter of our existing
capacity by 2020, which are ageing and unlikely to meet environmental
regulations. In the current system, maintaining the level of security of supply is
left to market forces.
The power sector needs to lead the decarbonisation of our economy, but the
current market has a bias towards fossil fuels.
that the power sector emissions need to be largely decarbonised during the
2030s.The Committee on Climate Change has recently proposed that the
power sector should be close to zero-carbon by 2030;
30% of our electricity in 2020 needs to come from renewable sources
(largely onshore and offshore wind), up from 7% today, to meet our legally
binding EU target.
Low carbon = renewable electricity (for example wind
and tidal technologies), nuclear power and new fossil fuel power stations
equipped with carbon capture and storage (
Technology to reduce or manage electricity demand
estimated that we need around £200bn in generation, electricity networks and gas
infrastructure. Of this at least £110bn would be needed in new generation and
transmission – over double the rate of the last decade
Without reform, the existing market will not deliver the scale of long-term
investment, at the pace we need, in particular in renewables, new nuclear and
Proposals are designed to strike a balance between the best possible
deal for consumers and giving existing players and new entrants in the energy
sector the certainty they need to raise investment. Specifically, they are designed to
ensure that low-carbon technologies become a more attractive choice for investors,
and adequately reward back up capacity to ensure the lights stay on.
(the 4 main measures)
Carbon price support
Strengthening the carbon price for
electricity generator will increase the cost of fossil fuel generation, ,
making lower-carbon power more attractive;
Emissions Performance Standard
: A back-stop to limit how much carbon
the most carbon intensive power stations - coal - can emit.
Ofgem’s review into the liquidity of the electricity wholesale market is an essential complement to these reforms, to safeguard competitiveness and the ability for new firms to enter and compete
It is vital that retail energy markets work to keep energy prices as low as possible, consistent with the need for investment to meet climate change and energy security objectives
PRICE CHANGE AHEAD
(Price of power should be) lower in the five year period up to 2030 than continuing with existing policies despite delivering a higher level of ambition
The key conclusion
the trend in bill impacts: small impacts on bills in the near term, but in the longer-term bills are expected to fall by 2030,
a White Paper in late Spring 2011, incorporating a
response to this consultation, and setting out detailed legislative and administrative proposals to support these reforms. The conclusions of the Ofgem Review will be published alongside, Legislation will follow as soon as possible thereafter and the transition to the reformed market will follow before the end of the Parliament
WALES, SCOTLAND, NI
Energy policy is generally a reserved matter. However, certain powers have been executively devolved to
, and the generation of electricity in
is fully devolved.
To ensure security of supply later in this decade and the
2020s, market design will need sufficient
investment in new base load, as well as flexible plant and other technologies
such as interconnection, storage and demand side response to balance the
Decarbonisation of the whole economy can be achieved most
effectively if the electricity industry is largely decarbonised by the 2030s so that electrification of heat and transport can follow
even as we keep overall demand for energy stable or reduce it, the
demand for electricity would be expected to increase, and potentially as much
as double by 2050
a longer term view introduces uncertainties:
the amount of energy we will need
the availability of resources
requires confidence to act, and an
understanding of the timelines needed to deliver large building and
infrastructure projects. Decisions made in the next decade will have
consequences for the next 40 years.
Over 19GW of nuclear, oil, coal and gas plant is scheduled to close over the coming decade as stations reach the end of their design lives and due to the effects of environmental legislation. Over 20 GW of new capacity is either in construction or development and will therefore enable the
to maintain secure supplies for the time being
This allows transport and heat to be electrified and
decarbonised in parallel.
Our primary objectives are to ensure the sector is largely decarbonised during the 2030s.
A supporting objective is to ensure that the target for 15% renewable energy
consumption across the
economy is achieved by 2020. This is likely to
mean circa 30% renewable penetration in the electricity market as this is one
of the lower cost and most mature areas for renewable energy deployment.
4 broad principles.
important that interventions are
affordable in absolute terms to electricity consumers and taxpayers.
Durability and Flexibility
robust to a number of unlikely outcomes regarding carbon prices, fossil fuel
prices, and technology costs.
the transformation of the
’s energy sector will be achieved
by balancing environmental, social and economic
attractiveness of the
electricity market is affected by other areas of
policy including the planning system, technology licensing and grid connection
regime that all support the development of major infrastructure. The Electricity
Market Reform project is not trying to address these wider factors, but we
recognise that they are critical enablers for investment decisions
’s electricity supplies are amongst the most reliable in
. While the current market provides incentives to align electricity production with demand, these may not be strong enough to overcome the additional uncertainty that arises as we deploy intermittent renewables.
HOW FREE MARKET RUNS ELECTRICITY
The current market has developed following liberalisation in the 1990s. The
intention was to create a competitive electricity system where prices are
determined without administrative price caps or other regulatory interventions
and where unfettered movements in price, and the freedom of
market participants’ actions (including contracting and hedging), would be the
main drivers of investment behaviour. This is similar in many ways to a range
of other commodity markets.
The electricity wholesale market is designed to be much like a typical
commodity market. Generators (those who produce electricity) sell electricity
to suppliers (those who sell electricity to consumers) through bilateral
contracts, over the counter trades and spot markets.
However, electricity cannot be easily stored, so to ensure a secure supply of electricity the amount being produced (supply) and the amount being
consumed (demand) must match at all times; the system must ‘balance’.
Electricity is traded in 30-minute blocks. This continues until an hour before the start of a block (a point called gate closure). At this point the volume of
electricity generators have contracted to produce and that suppliers have
contracted to consume should be equal (balance). They are incentivised to do
this by having to pay an imbalance penalty (cash out price) if they have not
contracted sufficiently to cover the amount they actually generate or supply to
After gate closure the responsibility for ensuring supply equals demand on a second-by-second basis is held by a central body (National Grid, the System Operator), as it is not technically possible to do this through bilateral trading.
This market structure has been effective. The liberal GB electricity market has
delivered increased choice in tariffs and services and enabled consumers to
FEED IN TARIFFS
feed-in tariffs for small scale generation – introduced in April 2010 this
scheme encourages the deployment of smaller renewable installations below
5MW, particularly by organisations, businesses, communities and individuals
not traditionally engaged in the electricity market. This scheme was introduced in recognition of the potential role communities could play in the
’s transition to a low-carbon economy. The Government is committed to
encouraging community-owned renewable energy schemes where local
people benefit from the power produced. The small scale feed-in tariffs are not affected by the reforms proposed in this consultation, which are aimed at
large-scale low-carbon generation
EU LINKED TO UK GRID
The Government supports further integration of EU electricity markets as this will increase security of supply and facilitate the move to a low-carbon
economy at least cost to consumers.
since privatisation and liberalisation. The
delivered the almost 30GW of gas generation currently in operation
maintained an adequate capacity margin (the margin of spare capacity in
excess of maximum electricity demand). This has resulted in low risks of
electricity demand not being met.
resulted in electricity prices which have been comparatively low and fairly
responsive to movements in fuel costs
supported the deployment of increasing amounts of renewables from 3.1GW
in 2002 to 8GW in 2009; and
reduced greenhouse gas emissions.
needs to dramatically reduce its carbon intensity. An opportunity for this transformation arises in the next decade when a large proportion of our existing coal and oil generation will close as a result of the new standards being introduced by the Large Combustion Plant Directive and Industrial Emissions Directive and as nuclear plants come to the end of their lives
. At the same time, the need to meet our legally binding EU renewable energy target will require a dramatic increase in the proportion of
electricity that is generated by renewables.
Figure 1, below, shows that under the current market arrangements
(including the RO) and without any additional form of Government intervention
we will achieve approximately 20% reduction in the carbon intensity of power
generation to 2020, rising to approximately 60% by 2030, relative to 1990
levels. Nevertheless, without reform, carbon intensity will not fall fast enough
Much of the low-carbon technology that could be deployed
this decade has high capital costs and is either only able to generate
intermittently (e.g. when the wind blows) or is inflexible and therefore has to
run continuously. These characteristics mean that the system will require flexible
capacity to respond to demand spikes or supply shortfalls.
also need technologies such as demand side response, storage, interconnection and new thermal plant to fulfil this vital role,
Without reform, spare capacity
will fall below a margin of 10% over the
. As margins fall there is an increasing risk of localised instances of
supply not meeting demand, yielding ‘energy unserved’ which take the form of
blackouts or voltage reductions.
Current high capacity margins are, in part, a reflection of slower than anticipated economic growth due to the recession;
gas is generally the price setting plant and can pass through any changes in gas or carbon prices to the electricity price. Therefore electricity and gas prices (and hence revenues and costs) tend to move together. By contrast low-carbon generators are price takers and are more exposed to gas or carbon price volatility.
finance requirements of low-carbon generation –
to support the
construction of £70-75bn of new plant in the next ten years will stretch and
possibly exceed the balance sheet capacity of incumbent firms. Therefore we
need to attract investment from new entrants.
a margin around 10% is generally considered to
provide an appropriate balance between the costs of spare capacity and the security of supply benefits
21. These factors combine to make low-carbon investment slow to come forward and expensive to develop which results in increasing concerns around the
efficiency and fairness
of the current design and the costs that it passes through to consumers.
conventional gas generation and biomass technologies to
balance the increasingly intermittent and inflexible generating mix we are likely to have in future
Interconnectors are physical links between GB and other electricity grids that allow electricity to be imported or exported in response to appropriate price signals.
currently has 2.6GW of interconnection which
is around 3% of peak GB demand. Different countries have differing peak
demand times, interconnectors can bring security of supply without extra investment in plant.allowing for export/import at times of high/low renewable output
Historic high capacity margins have meant that use of
demand side response (DSR) has been relatively limited in GB. The system
operator contracts approximately 200 MW of interruptible industrial demand fromlarge consumers (who stop energy intensive processes when instructed, in return for payment), as well as a limited amount of frequency control demand management. Apart from this, there are mechanisms such as the Economy 7 tariff which incentivise consumption, such as the charging of electric heaters, outside peak time
an important role for DSR in the future as it has strong potential to assist system balancing and reduce costs and a more dynamic demand side can reduce the power of market players on the supply side.
Currently, installed storage capacity in GB is just under 3GW and is largely made up of pumped storage, this being the only established technology at present.
An international example of DSR is from
, where EDF’s Tempo tariff informed customers in advance
of the electricity price for the next day using colour coded lights. Consumption was seen to shift on average by
as much as 45% between the most expensive (red days) and the cheapest (blue days).
even if the scheme’s current 2037 end date were extended the
Renewables Obligation would not be the most cost effective mechanism
28. Overall the Government assessment is that the current market will not provide signals for investments that will cost-effectively decarbonise the electricity system in the long term.
Current levels of EEU arising as a result of distribution level faults, for example trees falling on lines, are about 12GWh of outages per year
To put this figure into context, the total electricity supplied in the
in 2009 was almost 400,000GWh
The EEU from generation related problems has been near zero
suggests that an economically optimal de-rated capacity margin
could be around 8-12%. This could result in an estimated EEU of
around 0.5-4GWh per year could be mitigated through voltage reduction rather than actual power cuts
In voltage reduction, the system voltage is reduced by a few %, and so performance of heaters, lights etc diminish a little. This has no significant impact on customers, but after a while systems start to compensate e.g. a heater may run longer, a consumer may turn more lights on.
In the domestic and SME sector there are few Time of Use (ToU) tariffs available.
Lack of half hourly metering
This technical requirement is important for the
application of dynamic ToU tariffs.
DSR can play an important role in assisting DNOs to manage the network but they have no direct link to their customer base.
In terms of future investment in storage, high capital costs combined
with uncertainty over the future market, in particular the levels of volatility we
will see, are cited as the main barriers to further investment.
Wholesale price volatility is important to the commercial success of storage as arbitrage is fundamental to its business model: storage generally uses less expensive electricity in off peak times so that they are able to capture higher prices at other times..
There is considerable complexity in predicting levels of volatility as the market
goes through a period of unprecedented transition.
High capital costs
: Most storage technologies are in early stage of
development. The costs of many technologies do not compare favourably with
conventional generation technologies
. Other possibilities, such as using
electric vehicles to act as a store, are still uncertain.
This technology is geographically limited and obtaining suitable sites
may limit further build. However, whilst they may be limited, there are sites
which are thought to be suitable and have potential for development.
New power plants and grid
capacity are likely to cost over £110bn in capital investment to 2020. Of this,
about £70-75bn is likely to be investment in new generation capacity, and the
remainder in the electricity networks
. Moreover, energy utilities could also
face additional financing requirements in their supply and retail businesses, for example associated with the roll out of Smart Meters, gas transmission and distribution and renewable heat policies that could take the investment
challenge toward £200bn.
rising demand for capital may need to be met in the context of a shrinking
supply of capital from the incumbent energy utilities. Financial analysts and
other experts have suggested
that utilities are under pressure to moderate or lower their capital expenditure programmes and to find higher-yielding and
higher-growth opportunities as a result of high debt levels, pressure to grow
dividends , falling share prices and increased pressure on credit ratings. It is
likely that they will exercise maximum discretion these assets have
longer development and construction periods and more volatile returns. In
comparison, investment in the regulated network businesses likely to
be relatively easy to finance. This guarantees returns is low risk (and therefore attractive for debt financing)
additional sources of finance will be important, other developers
are essential. Indeed, a third of on-shore and offshore wind projects in the
pipeline at the moment are being developed by companies outside the “Big 6”
discussions with investors and lenders have indicated that there are a large number of risks associated with lowcarbon generation (such as planning, grid access, technology, construction and long-term availability) which may have a much greater effect in constraining the availability of finance than revenue uncertainties.
EU ETS continues to be the primary EU wide policy driving decarbonisation
across a number of sectors in the
EU ETS not sufficient to decarbonise the electricity sector at the pace required
Electricity sector to facilitate the decarbonisation of other sectors).
The Coalition Agreement set out three reforms to the electricity market:-
Carbon price, feed-in tariff or
) and an emissions performance standard (EPS)
Plans: a floor price for carbon
EPS prevent most carbon intensive unabated coal-fired power stations
Redpoint Energy report shows diff results under diff scenarios
/kWh by 2030. This is similar to the figure
previously recommended by the Committee for Climate Change in 2009. The
recent publication by the
for the 4
Carbon budget recommends a lower
figure of around 50gCO
/kWh as a medium scenario.. It compares to a
business as usual grid intensity of approximately 200gCO
Actual targets; next year when the Government sets the
’s fourth carbon budget
Net welfare is measured in terms of the net present value (NPV), which is the sum of all the costs and benefits
the impact assessment quantifies these costs, but does not capture the long term benefits of avoiding dangerous climate change.
overall costs to society
costs to society under all the options for reform when compared to the baseline
and as a consequence the NPV is negative
over the complete lifetime of the
low-carbon generation technologies, the Government would expect the NPV
would be positive.
a 30% reduction on 1990 levels rather than a 20%
reduction, carbon price estimates would be higher which would in turn
improve the overall NPV
carbon price support as part of reform the climate change levy (and fuel
duty) and is the subject of a separate consultation
decisions on the carbon price support mechanism will be taken at Budget 2011.
low-carbon generators do not have to pay a price for carbon
From 2013, the EU ETS emissions cap tightens each year However, for a variety of reasons, to date the carbon price has not been stable, certain or high enough to encourage sufficient investment in low-carbon electricity generation in the UK. Supporting the carbon price in the electricity sector in the
will increase the incentives to invest in
low-carbon generation. EU ETS will remain an essential prerequisite
floor for carbon creates investment certainty
High levels of uncertainty over future profitability and rates of return
could increase the cost of capital for investors and deter investment
capital could be diverted into less risky forms of generation.
achieved by the climate change levy (
) and fuel duty being levied on all
fossil fuels used to generate electricity in the
fossil fuels currently used to generate electricity are exempt from
. The Government proposes to remove these
exemptions and to tax
these commodities at rates that take account of their average carbon content.
Oils are not subject to
but fuel duty is payable at the point oil leaves the
refinery. Currently, the duty can be reclaimed in full by the electricity generator
Government proposes to reduce the amount of fuel duty that can be reclaimed.
carbon price would need to be increased significantly above the level delivered through EU ETS.
The modelling shows that it would need to reach £50/tCO
by 2020 and then
increase in a straight line to the 2030 target consistent price of £70/tCO
The key factor in the effectiveness of the policy is the reaction
of potential investors, and whether the mechanism is “bankable” for the
purposes of raising finance for new low-carbon generation investments.
it would need to be combined with a continued RO, or a feed-in tariff mechanism
it directly targets the carbon externality by putting a price on emissions and
maintains the role of carbon pricing and the “polluter pays” principle at the
centre of the Government’s decarbonisation strategy. In doing this, it also
maintains more of the competitive market signals that create incentives for
carbon price support policy is implemented through the tax system
increase the proportion of tax revenues from environmental taxes; and
make the tax system more competitive, simpler, fairer and greener.
RO s and FITs.
RO extended: require suppliers to source a certain percentage of their generation from low-carbon generation. Suppliers certificates to demonstrate they had met their obligation and these certificates would have a value which reaches the generator..
Feed-in tariffs are long-term contracts between government (or an
entity on behalf of government) and a low-carbon generator, giving a
guaranteed tariff or price e.g. for 15-20 years.
V: Lots about variations on fits, and effects on investment, ro’s rejected as fits better.
Extending £ support to ccs coal and nuclear is mega new step, slipped into the pot like a minor tweak.:v
Regulated Asset Base
(RAB) model is used by regulators as a mechanism
for providing a credible commitment to the recovery of the sunk costs
associated with capital investment by regulated monopolies. In the electricity
sector, a RAB model already applies to the development and maintenance of
transmission and distribution networks. licensees are allowed to add
efficiently incurred capital expenditure to their RAB and to make a return on
that investment in line with their average cost of capital through setting tariffs
the regulator in effect means a transfer of risk from the developer to the consumer
Construction risk is transferred because the RAB is adjusted periodically, to reflect changes
costs of capital for regulated businesses are lower than for unregulated businesses
as such a RAB could lead to a reduction in cost of capital and as such the
support costs needed to meet the
’s decarbonisation objectives.
significant loss of market efficiency signals
V: This is the tool to control coal (and later gas)
It is a backstop with low ambition – 600 – 450 grams co2 per mW.
The dominant consideration here is to keep our coal going, and gas because we need it as backup for intermittent renewables, as both coal and gas can be turned up and down. and there’s enough closure of coal on its way anyway.
Grandfathering means that whatever the level when the installation is built is the installation for its economic life, ie investors can be happy that costs wont go up. Certainty about profit is the word on the block.:V
V:And the eps can be turned of when needed ! :V
exceptions to the EPS where there are short-term or longer-term energy
supply emergencies. For example, in order to safeguard security of supply
such an exemption would allow coal plant, under tightly defined
circumstances, to turn off their
equipment at times of exceptional
demand and thus be able to output additional electricity to the grid, or it would
allow the plant to operate at a higher output (or load factor) than the
constraints imposed on its operation by an EPS.
‘zero rate,’ or otherwise differentiate, the
emissions from the biomass fuel when calculating plant carbon dioxide
the EPS are consistent with demonstrating
around 400MW (gross) of output of a new supercritical power station, and
therefore the Government does not expect any costs to the economy in
addition to the costs of the
an alternative - effectively imposing a running hours limit on all
fossil-fuel power stations, both new and existing. This limit would be then
progressively tightened such that by 2030 only fossil-fuel power stations
would be able to operate as baseload. The general effect
of this would be to increase the electricity price to a level where it was
economic for generators to invest in low-carbon generation, which typically
have higher costs (and higher risks). It would create significant security of
supply risks by driving early closure of existing plant and preventing new
investments in flexible generation plant.
Such an EPS is
unlikely to be viewed as a credible intervention by investors. Emissions limits
would be relatively straightforward for Government to change
Question 13: Which option do you consider most appropriate for the level of
Question 14: Do you agree that the EPS should be aimed at new plant, and
‘grandfathered’ at the point of consent?
Question 17: How should biomass be treated for the purpose of meeting the
EPS? What additional considerations should the government take into
Question 18: Do you agree the principle of exceptions to the EPS in the event of long-term or short-term energy shortfalls?
mechanism to explicitly reward the provision of capacity (as opposed
to only the energy from electricity generation). Such a mechanism would also be designed to reward demand-side response, to encourage the development of energy efficiency and other “smart” technologies.
a central body to maintain a set capacity margin.
This body would make an assessment of the level of spare capacity that will be provided through the energy market and then will run tenders for any additional capacity needed to make up the shortfall
Technologies such as demand side response, storage and interconnection
offer the opportunity to have a greater diversity of technologies, so improving
security of supply, as well as reducing emissions. A more dynamic demand
side also increases competition and the effective functioning of the market.
16. Demand side measures (energy efficiency, Demand Side Response (DSR)
and distributed generation) can reduce the need for investment in
infrastructure by reducing overall need and making more efficient use of
network and generation capacity. Experience from other markets (e.g. New
scope for immediate development lies in the industrial and commercial sectors with opportunities for aggregation of firm demand response, for example a supermarket chain being able to control usage of electricity for refrigeration across a whole network of stores.
DSR could be a particularly useful tool for Distribution Network
Operators(DNOs) whose role is to manage the local electricity networks. DSR
can reduce or delay the need for local network reinforcement by smoothing
peaks in demand. However, the DNOs have no direct relationship with
electricity consumers. Two of Ofgem’s recently announced Low-Carbon
Network Fund projects address this problem by promoting a partnership
approach between suppliers and DNOs.
19. Domestic consumption offers more potential post 2020 with the likely
electrification of heat and transport, which could significantly increase the
amount of discretionary electricity use available for DSR. Increased
automation via the introduction of smart appliances and widespread use of
automated building energy management systems could play a vital role in
assisting system balancing, empowering individuals and communities to
actively participate in achieving a low-carbon future.
The GB electricity system is currently relatively unconnected to other countries electricity systems
. Under the current arrangements, investments in interconnection are made on commercial terms, i.e. where developers identify an opportunity for arbitrage between markets then such investments take place. However, the nature of the investments make them high risk. As a
response, Ofgem is developing a new regulated approach to interconnector
investment which will be consulted on early in 2011. There is widespread
Reform of the cash out price will improve the economic
case for storage, by making the costs of imbalance higher and more cost reflective. low short run marginal cost plant will drive low prices at times of low demand. This should make storage a more attractive investment, because it increases the opportunity for arbitrage. today, the
only market-ready technology available for large-scale deployment is pumped
). Going forward as technologies mature, the costs will reduce
“recognised, financed and delivered on the basis that it is a power system
a range of measures on energy efficiency end in December 2012 and will be
replaced by the Green Deal. The Green Deal = offer all households and businesses in
energy efficiency improvements to their properties at no upfront cost.
consumers to pay back the costs over time through
energy bills. With payments being less than the expected savings, ie pay less than now.
DSR could increase customers focus on how they can use energy more intelligently through energy management
Intensive Industry Strategy, is a joint project between
DEFRA involvement, which will look at greenhouse gas abatement potential in
key energy intensive sectors, in light of the move to a low carbon economy.
potentially still be under-investment in particular in generation that
is only required to run occasionally. Further, due to the cyclical nature of
investment, there would continue to be a risk that capacity margins would
remain low in some years.
do not address all of the risks to security set out in Chapter 2 and that these are set to increase as the volume of low-carbon generation increases, the Government has concluded that in addition it is necessary to introduce a capacity mechanism in order to provide greater assurance of the future security of electricity supplies. this transfers the management of the risk associated with underestimating capacity to the government from market participants.
Instead of developers receiving all their revenues from electricity sales, they receive a payment that attaches value to capacity or resource being available
By providing a regular revenue stream, it should ultimately deliver greater
investment in new capacity by reducing the cost of capital
a capacity mechanism will bring forward significant demand side response, as demonstrated by the experiences in
Eg from all island ie
south and north
Capacity payments are made to generators based on a measure of their
availability. The payment is broken into three sections, a fixed amount based
on forecast demand, a variable amount based on expected levels of scarcity
and an ex post payment based on actual scarcity. This mix provides a balance between providing certainty and reducing gaming. Payments are funded by charges levied on suppliers based upon their electricity consumption.
The current PJM market (PJM=
is a Regional Transmission Organisation
serving much of the North East USA)
Demand side response and energy efficiency measures (negawatts) compete in the auction alongside generating capacity.
All contracted resource receive the auction clearing price for the periods they
are available, which is paid by an obligation on suppliers.
The independent SO holds a capacity auction three years in advance. To
reduce gaming the required capacity is not fixed absolutely, i.e. at low prices
the SO intentionally procures excess capacity, at high prices it procures less
than target, leaving some to be procured in incremental auctions up to the
Tender for Peak Load Reserve in
For illustration, the modelling
undertaken for the project, with a target margin of 10%, showed that in overall
net welfare terms a market-wide capacity mechanism had a negative NPV
impact of £0.78bn
and £0.7bn for a targeted capacity mechanism. However,
a positive NPV would result if a higher value was placed on security of supply
or if a lower target margin had been chosen.
61. The modelling did not include the potential for new DSR , costs could be lower with this included
impact of a capacity mechanism on consumer bills is expected to be
small. In the modelling, the market-wide capacity mechanism added around
1% to the average annual household electricity bill, in the period to 2030. The
effect of a targeted capacity mechanism would be minimal.
73. A capacity mechanism can be designed to reward energy efficiency for the permanent reduction in demand that it offers.
in the PJM 2012/13 auction, the first
PJM auction in which energy efficiency is eligible for a capacity payment,
568.9 MW of energy efficiency measures cleared the auction, 0.4% of the
Under a targeted capacity mechanism, energy efficiency measures, although
not contributing to the flexibility of the system, could potentially be rewarded
for the reduction in demand offered at peak hours.
this is more complex than including other demand side technologies. For example, there may be unintended consequences
has the potential for greater market distortion.
However, given the advantages of putting increasing supply and reducing
demand on an equal footing, this possibility should be explored further.
At times of system tightness, it is more efficient if the additional resource is located close to areas of high demand. This minimises system losses and avoids any network constraints on congested
areas of the network
in the market-wide capacity auction in (PJM) there are separate capacity
auctions for locations that are experiencing distribution or transmission bottlenecks
Different auctions could beheld for different geographical areas, so that resource in an area of high demand receive a price that is reflective of demand in that area.
it would mean, for example, that DSR was targeted at those geographical
areas in which it could provide most benefit.