Business School
Department of
Economics
Understanding the new
Capacity Market
implemented in the UK
ECONOMISING, STRATEGISING
AND
THE VERTICAL BOUNDARIES OF THE FIRM
Despina Yiakoumi and Agathe Rouaix
Discussion Paper in Economics No 16-13
December 2016
ISSN 0143-4543
Understanding the new Capacity Market implemented in the UK
Despina Yiakoumi
and
Agathe Rouaix
University of Aberdeen
Abstract
The UK Government has implemented a Capacity Market mechanism to deliver reliable
electricity at the minimum costs to the consumers, complementing at the same time the
decarbonisation agenda. Capacity Market intends to address the missing money problem of
the energy-only market. This paper provides an overview of the UK Capacity Market and
examines the outcomes of the two Capacity Auctions in the UK in relation to the objectives
of the government - energy trilemma - of reliability, sustainability and affordability.
1 Introduction
The composition of the electricity sector in the UK has gone through changes since
its liberalization in the 1990s. Until recently, the electricity generation in the UK has
been mainly relying on coal, oil and gas, which are responsible for high carbon
emissions. However, during the last few years British and generally European
electricity markets have been directed to achieve environmental goals and set
strategies for limiting climate change. The Renewable Energy Directive (European
Commission 2009) established that the UK obligation is to achieve 15 percent of its
total energy consumption form renewable sources by 2020. As a result, there has
been a movement towards renewable resources of energy and their presence in the
energy sector is being more and more evident. According to DECC (2015)
renewable generation capacity in the UK has more than doubled between 2010 and
2014. However, increasing substantially the percentage of electricity generated by
renewables poses new challenges for the design of electricity markets.
In addition to the target for energy consumption from renewable resources, the
Climate Change Act 2008 (Great Britain 2008) established that the UK carbon target
is to reduce by 80 percent the Green House Gases (GHG) by 2050 with respect to
1990 levels. As the power system decarbonises, about 11.5GW of coal and oil plants
are schedule to withdraw by 2016. Moreover, the UK faces very rapid closure of
existing capacity as older plants go offline. More precisely about 6.5GW of nuclear
power plants are expected to close by 2020. In total, by 2020 around 18 GW of
energy power, which equals to 22 per cent of the current capacity, are expected to
be shut down. Their capacity will need to be replaced. This, along with concerns,
which are presented in part 2.2 of this paper, that the electricity market in the UK is
unlikely to bring forward new, reliable, low carbon capacity, brought to light some
concerns associated with the design of the electricity market.
UK Government has recently introduced significant reforms in the design of the
electricity market and has implemented a government policy; the Electricity Market
Reform (EMR). The general objectives of this reform are the security of electricity
supply, the decarbonisation of the energy sector and the improvement of affordability
for consumers. Together these three objectives constitute the “energy trilemma”.
EMR introduces two mechanisms to fulfil the aforementioned objectives; the
1
Capacity Market and the Contracts for Difference (CfDs). This paper focuses on the
Capacity Market implemented in the UK. It aims to provide an overview of how this
Capacity Market operates and what are the emerging issues in the current structure.
Next section presents a more detailed discussion of the UK electricity market and its
problems, as they have been identified by the Department of Energy and Climate
Change (DECC), and subsequently the justification for a Capacity Market. Section 3
provides a description of what the Capacity Market is and how it operates in the UK,
while section 4 introduces some key characteristics of the Capacity Market that
might affect the outcome. Section 5 presents the results of the two Capacity Auctions
that have already been concluded. A summary is presented comparing the
objectives of the Government with the results of the two Capacity Auctions, including
a discussion of the problems that can be identified with the current structure of the
Capacity Market.
2 Electricity market in the UK
Background on the electricity market in the UK
In the late 1980s, the electricity industry in the UK pioneered the liberalisation of
electricity markets. The purpose of the government was to promote competition in
the electricity market through an electricity pool system. In the late 1990s, the
electricity market was reformed again to create the New Electricity Trading
Arrangements (NETA); a net-pool system covering England and Wales. In 2005, it
was extended to cover Scotland under British Electricity Transmission & Trading
Arrangements (BETTA). In BETTA wholesale energy-only market generators and
suppliers can sell and buy electricity respectively in forward and future markets, in
short-term bilateral markets and in the Balancing Mechanism. System Operator
(SO), i.e. the National Grid, operates the Balancing Mechanism and its role is to
match supply and demand on a second -by-second basis.
NETA/BETTA is designed as an “energy-only” market. In this market revenues to
generators come from the sales of the electricity they generate throughout the day1.
The electricity demand during a day is inherently variable and can be covered by a
1Small
amount of the total capacity (around 0.4GW out of 70GW) holds long-term contracts for the
Short Term Operating Reserve (STOR) which is used by the SO in the Balancing Mechanism. This
capacity receives payments for their availability in addition to their output.
2
heterogeneous mix of generation technologies. The different technologies have wide
variations in terms of generation flexibility (i.e. speed with which the plants can ramp
up and down in terms of production), capital and operational costs. Typically,
technologies that can vary their output more flexibly have high marginal costs, while
the less flexible technologies have lower marginal costs (CMA 2016c).
The baseload demand is covered by the so-called “baseload power plants”, like
nuclear plants. These plants have high capital costs, low variable costs and are
inflexible thus, they prefer running continuously at a constant output. The
intermediate demand in the UK is covered by coal and combined cycle gas turbines
(CCGT). At times of peak demand stress, the peak demand is covered by open cycle
gas turbines (OCGT) or oil-fired plants. These “peak load plants” have low capital
costs, high variable costs and change their output easily providing flexibility to
electricity output. 2
The theory of well-functioning competitive energy-only electricity markets is that the
electricity price is sufficient for all generators, to recover all their costs and also to
provide them with adequate incentives for capacity investments (Bohn, Caramanis &
Schweppe 1984). The peak producers can only recover fully their sunk capital costs
at very occasional peak times - for example once every 20 years - when the price
rises extremely (CMA 2016b). During these times, the prices would rise sufficiently in
order to cover both the operating costs and the sunk capital investment costs of a
plant. These extreme prices benefit not only the peak and intermediate load plants
but the base load plants as well. However, the base load plants manage to recover
their sunk costs during ordinary periods where prices are not extremely high, since
they generate and sell electricity almost all the time and they have low operational
costs.
The theory of energy-only markets says that the promise of these very rare and very
high rents in periods of extreme demand is sufficient to reward the generators and
give them incentives, either to retain an existing plant or even invest in new capacity.
In particular, generators are able to receive scarcity rents when the price rises up to
the level of the average Value of Lost Load (VoLL). At this price the consumers on
average would not be willing to pay for electricity (CMA 2016b). However, in practice
2
More information about the electricity generation mix in the UK is presented in appendix I.
3
there is considerable doubt that the energy-only market would operate as theory
predicts. While the electricity market in the UK has historically delivered sufficient
investment in capacity, the market is predicted to fail in the future (DECC 2014a) .
The main concern associated with BETA wholesale energy market in the UK is that it
will not provide adequate incentives for investment to deliver reliable and flexible
generating capacity. This is due to a variety of reasons being outlined briefly below
as they have been identified initially by DECC in Electricity Market Reform White
Paper (2011b).
Electricity market concerns
In the Electricity Market Reform White Paper, DECC has identified potential market
and regulator failures that might be causing disincentives for investment in new
capacity in the UK energy-only market. Principally this might be due to low potential
revenues in the energy-only market resulting in underpayments to generators. This
phenomenon is widely known as the “missing money problem” and undermines
incentives to generators to maintain an old plant or even build a new one creating
concerns about security of supply. This problem exists due to the three reasons
presented below.
Firstly, energy companies are concerned that they will not be allowed to charge
extreme prices, even when the wholesale energy market prices peak to high levels 3.
Investors are concerned that the Government/regulator will act on high prices as
market power abuse and for example introduce a price cap to keep electricity
affordable for the consumers. For instance, other energy-only markets such as the
Nord Pool Day Ahead market in Germany and in Sweden have a price cap at €3,000
per MWh (where MWh means megawatt-hour), meaning that bidders cannot submit
bids higher than this price. In the absence of extreme prices, generators, especially
owing peaking capacity, will not be able to recover their sunk capacity costs fully.
This problem is exacerbated if there are barriers to entry in the market (such as low
level of liquidity 4, big electricity price uncertainty, high sunk costs) restricting the
3Transmission
Constraint License Condition (TCLC) and the European regulation REMIT: impose
severe penalties for specific type of market manipulation.
4
Liquidity describes the volume of trading in the market. Liquid markets enable participants to buy or
sell a product without causing a significant change in its price and without incurring significant
transaction costs.
4
number of market participants and thus, giving participants more opportunities to
exercise market power. This could result in greater difficulties in differentiating
gaming from market-driven prices, increasing the risk of Government’s intervention.
Although price caps in some markets, such as in Nord Pool Day Ahead market in
Germany and Sweden, do not seem to constitute a capacity adequacy problem 5,
since this maximum price is rarely achieved, in other cases price caps seem to be
too low (RW.ERROR - Unable to find reference:179). The Electricity Reliability
Council of Texas (ERCOT) until 2012 had a price cap equal to $3,000 per MWh.
After 2012, they decided to increase the price cap gradually to $9,000 per MWh by
2015. The rise in energy price cap in ERCOT occurred to ensure resource
adequacy. More specifically, electricity prices during August 2011, hit the $3,000
price cap for 17 hours, reflecting the tight conditions in the market. This signalled that
more capacity was needed in the market to cover the increasing demand for
electricity. By setting a higher price cap, generators could charge higher prices and
thus new capacity could be attracted in the market (RW.ERROR - Unable to find
reference:180).
In previous years in the UK, this has not been a significant concern, since wholesale
market prices historically have not risen above £938/MWh, due to the excess
capacity in the market. However, the factors that were responsible for the excess
capacity no longer hold. Firstly, the majority of this capacity was built prior to the
introduction of the NETA energy-only market in 2001. Secondly, the reduction in gas
prices during the 1990s, increased the investments in new gas plants, while there
was sufficient coal capacity in the market. Thirdly, the financial crisis in 2008 and the
resulting drop in the rate of economic growth decreased electricity demand for that
period (DECC 2014a). According to DECC (2014a), flexible plants in the future might
need prices up to £10,000 per MWh (or even higher) for short periods, to be able to
recover their sunk investment costs. However, investors are concerned that, if this
were to happen, the Government/regulator would intervene by restricting prices not
to rise at that high price. The perception of this regulatory risk could prohibit extreme
prices and investment in new capacity.
5 Capacity adequacy means that there is enough capacity in the system to meet the expected highest
level of electricity demand.
5
Secondly, as already mentioned in introduction UK aims to make large reductions to
power sector’s carbon emissions and thus, turns to low carbon technologies and to
renewable energy sources which are likely to be inflexible and intermitted (e.g. wind,
sun). The renewable energy exacerbates the missing money problem by reducing
the average wholesale electricity price and by displacing the conventional plants. As
a result, conventional generators (especially peak) increase their reliance on
infrequent and uncertain periods of system stress to be able to recover their costs.
This uncertainty causes disincentives to generators to invest in new capacity at the
same time when flexible and reliable capacity is needed to support the irregular
renewable resources.
The NETA/BETTA system has not been in existence for a long period of time relative
to the expected frequency of extreme events and thus, the system was not tested in
terms of extreme conditions. As a result, it is not clear under this system if the
investors could recover their sunk costs. The UK witnessed new investment in CCGT
in the early years of the 21st century. However, some evidence from company
corporate documents show that at least some generators believe that there has been
a missing money problem (CMA 2016b). In 2012 gas-fired generation was barely
profitable in UK (Hach, Chyong & Spinler 2016).
Thirdly, the electricity price does not reflect the full cost of the SO balancing actions
in the Balancing Mechanism, such as the use of reserve capacity or voltage
reduction 6, when there is a scarcity event. The charges to generators or consumers
who generated or consumed more or less electricity than they have contracted for,
are equal to the “cash out” or “imbalance” price. These cash-out prices provide
incentives for generators and suppliers to invest in resources to be in balance and
meet demand in scarcity events. However, cash-out prices and thus, the opportunity
cost of imbalance do not fully reflect the costs to the SO of balancing the system.
SO’s auctions are averaged when priced and the cost of the voltage reductions and
customer disconnections are not included at all into the calculation of the cash out
price. As a result, the missing money problem is exacerbated and the incentives to
invest or maintain flexible, peak capacity are reduced. To face this problem, the
Office of Gas and Electricity Markets (Ofgem) decided to introduce changes to the
6
Voltage reduction is costly: it causes equipment to run less efficiently.
6
calculation of the cash-out prices. In April 2015, Ofgem approved a set of reforms
under the Electricity Balancing Significant Code Review (EBSCR) (CMA 2016a).
There is an additional market failure from reliability, i.e. the protection against
unanticipated outages, being a quasi-public good. It is non-excludable in the sense
that consumers cannot choose their desired level of reliability and they cannot buy
reliability for themselves without providing it for everyone else. Earlier studies
demonstrated why the reliability of electricity has public good aspects (PSERC
2008). Regardless of their preferences and their willingness to pay for reliability,
each of them receives an identical quality of the service. According to economic
theory, public goods can never be provided by a free market. This is because
consumers are not willing to contribute on acquiring public goods, since there is the
belief that others would provide it anyway and thus, they prefer to “free-ride” on
others. For example, when a local line fails, any neighbour who pays for upgrades
and redundancy will automatically have this improvement extended to nearby
neighbours who are served from the same lines. Unless everyone is forced to make
contribution for reliability, there will not be enough demand for generation companies
to provide it.
Market failures and security of supply have emerged as problems not only in the
energy market in the UK but in “energy-only” markets all over the world. Joskow
(2008) states, that there is empirical evidence that the energy-only markets in the US
suffer from the missing money problem. The various arguments for these failures
have been covered in the literature (Joskow 2008, Cramton, Ockenfels & Stoft
2013). To address these failures and especially the missing money problem, several
countries have implemented Capacity Remuneration Mechanisms (CRMs). The
discussion about these mechanisms concentrates on whether the various market
and regulatory/political failures are sufficient to justify a capacity mechanism and if
so, what form it should best take 7. Various forms of CRMs have been used
worldwide and the general ideal is the remuneration of capacity for being available,
regardless of the energy produced. For example, capacity payment mechanism is
used in Spain, Strategic reserve in Sweden, Capacity obligation in France and
7
The range of CRM is illustrated in appendix II.
7
Capacity Auctions in PJM and New England in US 8. Among the different choices, the
UK has chosen and implemented a Capacity Market with Auctions and the design
was based on experiences from other Capacity Markets in the word, especially PJM
and the ISO- New England Capacity Markets in the US (DECC 2011a, DECC
2014a).
In conclusion, the missing money problem, increases risks for investment in
conventional capacity exactly at a time when the UK needs new reliable and flexible
capacity (e.g. efficient gas plants) to support the intermitted renewable resources. At
the same time existing ageing polluting plants need to be replaced and more
capacity is needed to satisfy the potential increase in future demand for electricity as
a result of the electrification of the transport and heating systems. Subsequently,
while there have always been risks that an energy-only market might fail to provide
sufficient incentives for investment in new capacity, these risks and uncertainties
have become more significant and more apparent currently in the UK. According to
DECC (2014a), although there is no immediate threat of security of supply,
generation capacity is expected to fall over the next couple of years. As a result, UK
Government decided to introduce measures to support new investments in reliable
and flexible capacity by implementing a Capacity Market with Auctions (DECC
2014a).
3 UK Capacity Market
What is a Capacity Market?
DECC has addressed the missing money problem by implementing a Capacity
Market with Auctions, a mechanism that will remunerate capacity for being available,
regardless of the energy produced. UK first capacity auction was held in December
2014 for delivery in 2018/19 and the second one was held in December 2015 for
delivery in 2019/20.
The Capacity Market will provide steady and predictable income by remunerating
plants based on their capacity and availability during stress periods. This income will
be in addition to the revenue from the energy-only market which is calculated based
on their output. The capacity payment is believed to address the missing money
8 For more detailed description about the different CRMs see the study from the Algerian Regulatory
Commission for Electricity and Gas (Algeria CREG 2014).
8
problem and encourage sufficient investment in reliable and flexible capacity and
provide incentives for existing capacity to remain open (DECC 2012). In exchange
generators must deliver energy at times of system stress or they face penalties. This
should provide generators with a powerful incentive to produce electricity when are
called, by scheduling maintenance, faster ramp-up times, keeping the plant warm as
needed, employing the right number of staff to maximise reliability (DECC 2013b). In
this way the Capacity Market aims security of supply which is the major objective of
the Government. The implementation of the Capacity Market should occur at a
minimum cost to the consumers avoiding at the same time unintended
consequences by ensuring compatibility with other policies such as the
decarbonisation of the power system (DECC 2014a).
Generally, adding an additional capacity revenue stream for generators will have
important effects on the energy market according to the Impact Assessments
published by DECC (2011a, 2013a). Firstly, the levels of capacity in the electricity
market will be higher than in an energy-only market and the generators will cover a
portion of their sunk fixed costs in the capacity market. The cost to consumers of the
capacity payments might be partly compensated through lower prices in the
wholesale electricity market. Modelling shows that the Capacity Market might lead to
a decrease in wholesale prices in some years but increase in wholesale prices in
other years up to 2030. These results are supported by analysis from Redpoint
Energy (2013) which was commissioned by DECC to undertake an independently
review of the Capacity Market Impact Assessments.
However, more recent analysis by DECC (2014a) showed that the Capacity Market
might lead to lower and less volatile wholesale prices throughout the years up to
2030. There is still some uncertainty around the impact of the Capacity Market on
the generators’ pricing behaviour in the energy-only market and thus on the
wholesale prices. Experience from ISO-New England shows that the Capacity
Market brought forward enough capacity in the energy market but the wholesale
energy prices are quite volatile. Because the majority of the generating plants in
New-England run on natural gas, the price of the wholesale electricity price
fluctuates with the price of this fuel source (ISO-New England 2016).
In the next part the different features of the Capacity Market will be explained.
9
Capacity Market implemented in the UK
The Capacity Market with auctions is composed by a number of steps, as it is shown
in figure 1 below. The total process will be first explained briefly and thereafter a
more detailed description will be given for the main stages of the Capacity Market.
Figure 1: Capacity Market process
As it is illustrated in figure 1, the target capacity, which is the amount to be
auctioned, is first determined about 4 years and 6 months before the delivery year.
Subsequently, all the resources that are eligible to participate in the Capacity Market
must go through the prequalification process which is run by the SO. The resources
are called Capacity Market Units (CMUs). The CMUs that pre-qualify will then enter
into a descending clock, pay as clear auction which is held four years ahead of the
delivery year (T-4 auction) and it is also run by the SO. A secondary auction takes
place one year ahead of the delivery year (T-1 auction), which enables CMUs that
were not ready for the T-4 auction to participate in the Capacity Market. A secondary
trading follows the T-1 auction and continuous during the delivery year. It gives the
opportunity to the participants to mitigate risk of penalties if they are unable to meet
their capacity obligation. During the delivery year capacity providers will receive
monthly payments for the contracted capacity in exchange to their commitment to
10
provide electricity when they are called. The cost of the capacity payments will be
shared between the suppliers which will be passed through to consumers’ bills.
The details on how the Capacity Market is operating are set out in the Electricity
Capacity Regulations (2014) and the amendment Capacity Market Rules (DECC
2016b). However, the different features of the mechanism will be briefly explained
below.
Target capacity
The target capacity level is the total amount of capacity needed to meet the peak
demand during the delivery year, i.e. in four years’ time. The Government (Secretary
of State) establishes the reliability standard for the capacity market, which will be
expresses as a loss of load expectation (LOLE). LOLE expresses the average hours
per year supply is expected to be lower than demand for electricity. The reliability
standard published in the first EMR delivery plan is a LOLE of 3 hours/year. In this
sense 3 hours per year SO is expected to use mitigation actions, e.g. use of reserve
capacity, to avoid significant effects to consumers such as blackouts.
The SO carries out an annual security of supply analysis and advices the amount of
capacity needed for the reliability standard to be met 9. Subsequently, based on the
results, Government decides on the amount of capacity to be auctioned. The target
capacity is used to establish the demand curve which is published before the
auction. The demand curve will be analysed in detail in section 4. The determination
of the capacity target is currently outside the scope of paper.
Prequalification
Before participating in a Capacity Auction, companies need to prequalify the
resources for which they would like to participate in the Capacity Market. This part of
the paper presents what information each participant must provide and actions they
must take during the prequalification stage, which are more likely to affect the
outcome of the auction.
9
Target capacity is calculated taking account of the capacity that will not participate in the Capacity
Market, i.e. capacity secured via previous auctions, capacity to hold back for the T-1 auction, eligible
capacity chose not to participate in the Capacity Market but will be operational during the delivery
year and all the resources that are not eligible to participate in the Capacity Market such as
renewables. More information about eligibility see the Prequalification stage section.
11
The information submitted during this stage is needed to verify that each CMU is
eligible to participate in the auction and to establish its size. The eligible resources
are the generating CMUs, Demand Side Response (DSR) 10 CMUs, storage and
interconnectors are also eligible since 2015 and onwards. The Capacity Market is
not obligatory for all eligible resources but the prequalification process is. The
Prequalification stage also enables licensed owners of existing generation capacity
to notify their intention to Opt-out of the Capacity Market even if they will still be
operating during the delivery year. This information is used to update the target
capacity in the auction after the prequalification stage is completed.
Forms of capacity that are already receiving support through other schemes are not
eligible to participate in the Capacity Market. In more detail capacity receiving low
carbon support (e.g. Renewables Obligation (RO), Feed in Tariffs (FiT), Contracts for
Difference (CfD), Renewable Heat Incentive Scheme Regulations) and capacity
holding long-term contracts for the Short Term Operating Reserve (STOR) 11 during
the delivery year are not eligible to participate in the Capacity Market.
There are different pre-qualification criteria depending upon whether the applicant is
an existing generating plant, an existing plant seeking support for refurbishment called refurbished, a potential new plant, existing interconnector, new interconnector
or a DSR provider. A refurbishment plant is an existing plant that needs to spend a
significant amount of capital on refurbishments (above a pre-determined threshold)
so that plant can stay open and operational 12. During the prequalification stage,
generators could apply and qualify for both, the refurbishment and the prerefurbishment/existing stage of their plants. Depending on this separation, the length
of their capacity agreement in years, in case they are awarded one, will be different.
Contracts that last one, up to three, or up to 15 years are available. New generating
CMUs are eligible for the longer contracts but operators must prove that they are
spending above a certain threshold on building their plant. For the 15-year contract,
that level of expenditure was set at £255/kw capacity in the latest (2015) auction; for
10
Demand side response is the scheme where customers reduce their electricity use during peak
times and in exchange they receive payments.
11 STOR: Capacity used by the SO in the Balancing Mechanism and are already receiving payments
for their availability in addition to their output.
12 An example of refurbishment plant could be a coal plant which is being considered to fit Selective
Catalytic Reductions (SCR), which reduces the plant’s carbon emissions and allows the coal plants to
stay open longer under the Industrial Emissions Directive.
12
the three-year contract the threshold was £130/kW (National Grid 2015b). Any
capacity spending less than these amounts would only have access to one-year
contracts. Refurbishment generation units are eligible for an agreement of up to 3
years if the refurbishment requires capital costs above the three-year capacity
expenditure threshold 13. Existing generating plants are eligible for one-year capacity
agreements as the DSR providers. The exact criteria about the eligibility of each
CMU to specific capacity agreement length are presented in chapter 3 of the
Capacity Market Rules (2016b).
The different availability in capacity agreement length among various technologies
and investments means that, if costs are higher, then, longer contracts could provide
more revenue certainty and thus it will be easier for new technologies to maintain
finance. For example, a nuclear power plant that is committing to one-year
availability, (during a period when it will be generating anyway) is competing on price
in the same auction against new projects such as a CCGT plant that is yet to be built
and is committing for up to 15 years of power availability (Orme 2016).
Auction
Providers of capacity participate in a descending clock pay as clear auction four year
ahead of the delivery year with a supplementary auction held one year ahead of the
delivery year. The amount of capacity contracted at the T-1 auction is determined
based on assumptions of how much DSR is expected to come forward. According to
DECC (2014a), the secondary auction enables DSR to participate in the Capacity
Market since it is very difficult for this capacity to participate in an auction, four years
prior to delivery. The T-4 auction allows adequate time for new entrants that were
awarded with capacity agreements to build capacity needed for the delivery year, but
at the same time there will be a significant uncertainty around the target capacity
level. The T-1 auction is useful to refine the capacity level and purchase additional
capacity if required.
The participants that are successful in the auction are awarded capacity agreements
and they are committed to meet their obligation when needed during the delivery
13
In most cases a Refurbishing CMU will not be eligible for an agreement of up to 15 years even if the
intended capital expenditure is above the 15 year Minimum £/kW threshold. A CMU is only eligible for
an agreement of up to 15 years if it also meets the Extended Years criteria for new plant set out in the
Rules.
13
year otherwise they face penalties. Penalties are applied as a way to tighten delivery
incentives. Another scheme used to incentives delivery, are the termination fees.
Generators of refurbishment and new generating CMUs are subject to these fees
and they aim to incentivise them to be on time with the refurbishment or building of
their CMU. After the T-4 auction the refurbishment and new CMUs that are awarded
a capacity agreement are required to satisfy the Financial Commitment Milestone by
no later than 18 months after receiving the auction results. They are also required to
keep the Delivery Body inform of the progress of the Construction or Refurbishment
of their plant until it achieves an output of 90 per cent of its capacity. This is called
the “Substantial Completion Milestone”. More information about the termination fees
are set out in Chapter 6 of the Capacity Market Rules. The importance of the
termination fees will be highlighted in the Results section of this paper.
Secondary trading
A secondary trading takes place after the T-1 Capacity Auction and continue through
the Delivery Year, where capacity providers can adjust their capacity obligation
position. Participants can trade their obligation in advance of a stress event by
physical trading if they are unable to meet their obligation. They could also reallocate
volume following a stress event. Volume reallocation allows capacity providers who
have over delivered to transfer excess output of their CMU to a different CMU which
did not deliver all of its obligation. Secondary trading is outside the scope of this
paper. More information about the rules of secondary trading are set out in chapter 9
and chapter 10 of the Capacity Market Rules.
Delivery year
The Capacity Market requires resources that receive capacity payments from it to be
available in periods of system stress. The SO will deliver a “Capacity Market
warning” at least four hours prior to any expected stress event. The Capacity Market
warning is a signal for providers to deliver their obligation in four hours’ time if a
stress event occurs at that time.
Capacity Market participants bid in the auction the de-rated capacity 14 of their CMU
in kW (where kW means kilowatt). However, their obligation is to deliver energy
14 De-rated capacity means that the capacity is adjusted to take account of the availability of the plant,
specific to each type of generation technology
14
equal or greater than their “Adjusted Load Following Capacity Obligation” (ALFCO)
which is a volume in MWh during a System Stress Event to avoid penalties. The
formula for the calculation of ALFCO in the Capacity Market Rules section 8.5.2
(DECC 2016b) is complicated but generally it makes allowances for the provision of
certain balancing services. Moreover, it ensures that the capacity obligations will be
“load following”, meaning that providers are required to deliver a percentage of their
obligation that is proportional to the percentage of the demand at the time of stress
event (National Grid 2015a). Load following obligations ensures that generators are
more likely to operate efficiently, reducing by this way the emissions and the
consumer bills in comparison to the case that they deliver their full obligation when
the demand does not require doing so (DECC 2013b).
There are two cases where capacity agreement holders avoid penalties after the
Capacity Market warning. First, if the capacity agreement holders have already a
contract in the BETA energy-only market (either by participating in the forward/future
market or in the day-ahead market) and they are producing their ALFCOM, then
these participants fulfil their capacity obligation. However, the capacity agreement
holders that do not hold a contract in the energy-only market, and thus they are not
supposed to produce electricity, must in four hours’ time to manage to bring their
plant in operating status and deliver their obligation. In this case the payment they
will receive for the electricity output production in the energy-only market is
calculated based on the cash-out price.
The capacity providers who will not be able to deliver during stress periods are
financially penalised, with a penalty rate (£/MWh) at 1/24th of the relevant auction’s
clearing price for each obligation, adjusted for inflation. Penalties are capped at
100% of a Capacity Provider's annual Capacity Market payment with respect to a
CMU, and at 200% of a CMU's monthly Capacity Market payment. The penalty
regime aims to provide sufficient incentives for resources to be available when
needed and thus it provides some degree of investment in flexibility. For instance,
generators would like to invest in faster ramp-up times to make their plants able to
produce electricity when are called. On the other hand, if a plant cannot start up in 4
hours, such as the nuclear plant, the owner of the plant would need to believe that it
is likely to be operating in the energy market by having a contract in the BETA
wholesale market in order to avoid penalties for non-delivery (CMA 2016b). A four15
hour warning period is sufficient for National Grid to make an accurate assessment
of the possibility of a stress event. These penalties will not apply where no Capacity
Market warning was given at least four hours in advanced. In addition, this time
period is thought to be enough for plant operators to adjust their output based on
their obligation avoiding by this way the penalties.
However, during the stress event, the providers that deliver more than they are
obligated will receive over-delivery payments for the excess delivery at “the inverse
of the penalty rate” (DECC 2013b). Over-delivery payments will be funded from the
penalty payments and will be payable at the end of the year “at the lower of the
penalty rate or the total penalty revenue divided by the total over-delivery volume”
(DECC 2014b). The over-delivery payments will be available at the end of the year
instead at the end of each month which included a stress event, so that providers will
receive a more equitable share for their over-delivered capacity. The capacity
payments will flow from suppliers to providers of capacity and where penalties are
applied to providers, the payments will flow from them to the suppliers.
Next section describes the auction format used in the Capacity Auctions in the UK.
4 UK Capacity Auction
Description of auction format and pricing choice
The auction format chosen for the UK is a descending-clock, pay-as-clear auction
and the bidders are paid the last-accepted bid. The auction runs in a descending
clock format in discrete bidding rounds meaning that the price of the auction starts at
a high price (called price cap) and the auctioneer reduces the price in each round by
a set decrement. Pay as clear means that the winners of the auction are awarded
the same price which is determined by the last accepted bid.
In each round the auction price is bounded by the bidding round price cap and the
bidding price floor and each participant has two choices; either to stay in the auction
or exit the auction. If participants want to exit the auction they need to submit exit
bids for their CMUs and as soon as a CMU exits it cannot re-enter into the auction.
The exit bid is the minimum price at which a participant would accept a capacity
agreement and it could be any price between the current bidding round cap and the
round price floor. If the participant chooses to continue to the next round it means he
16
is willing to accept a lower price than the price floor of the current round (DECC
2016b).
As the price descends in each round and participants submit exit bids, the total
capacity remaining in the auction decreases with price. The auction ends at the
bidding round where the supply curve intersects the demand curve, meaning the
total capacity remaining in the auction is equal to the capacity demanded. This
round is known as the Clearing Round and the price of the auction is called clearing
price and it is either determined by Exact Match or by calculating the Net Welfare
Algorithm 15. All the participants that have not submitted an exit bid above the
clearing price will be winners of the auction and all receive capacity agreement at the
clearing price.
DECC has performed Impact Assessments of the proposals of the Capacity Market
(DECC 2013a) and it assumes that the generator bids in the Capacity Market are
based on the missing money required by each generator, i.e. the difference between
expected revenues from the energy-only market and the costs. The model does not
consider bidding strategies that deviate from these principles, for example
withholding capacity to increase prices. Hence, there is a risk that capacity payments
could exceed those modelled by DECC, leading to higher consumer bills (Redpoint
Energy 2013).
It is assumed that competition between bidders in the Capacity Market should drive
the price as low as possible. However, the capacity auction is thought to be
vulnerable for gaming opportunities, in particular if participants are able to exercise
market power by withholding capacity to drive up the price of the auction or by
bidding in much higher price than necessary. As a result, a number of mechanism
such as the auction parameters, have been implemented in the Capacity Market in
the UK, to mitigate gaming and market power opportunities (DECC 2014a).
Auction parameters
The design of the Capacity Market to minimise the creation of gaming opportunities
has been influenced by the experience of other Capacity Market mechanisms such
as the PJM and the ISO-New England (DECC 2014a). The different approaches
15More information about the calculation of the clearing price determined either by exact match or the
net welfare algorithm in appendix III.
17
that have been adopted, such as the characteristics of the demand curve, the price
taker threshold are presented below.
4.2.1 Key elements of the demand curve
Ahead of the auction, DECC establishes the demand curve the auctioneer will use to
determine the amount of capacity to procure. The major elements of the demand
curve are the target capacity level (already analysed in section 3), the net cost of
new capacity (net-CONE), the slope of the demand curve and the price cap.
Net-CONE
Net-CONE is the estimated level of capacity payment necessary to incentivise a new
plant to enter into the market. It is evaluated using financing costs, construction costs
and expected future earnings from the energy-only market. For these earnings,
investors would consider the expected energy prices and the expected capacity
utilization of their CMU. In the case of the UK Capacity Market, net-CONE is
currently based on the lowest Capacity Market bid of a new Combined Cycle Gas
Turbine (CCGT)16. In other words, it is “the estimated level at which new build CCGT
plant will bid into the Capacity Market” (DECC 2014a). Net-CONE also determines
the price that Government is willing to buy the target capacity level. It is assumed
that this parameter will be enough to give the appropriate incentives to the
generators to invest in new efficient gas plants. The net-CONE was set at £49/kW for
the T-4 auction in 2014 and 2015.
While the demand curve is set against the reference cost of a CCGT technology,
entry by other technologies is possible if these are economic (CRA 2013). For
example, a small embedded 17 diesel engine would have higher variable costs but
lower capital costs. If the missing money of this technology is lower than the CCGT
then the small diesel engine will be more efficient and will occur in preference to the
reference CCGT technology. Evidence from the Capacity Market in the PJM support
the above, since for almost a decade capacity prices in PJM were far below the Net-
16
Initially, the net-CONE level was determined at £29/kW/year based on the level at which a new
(peaking) OCGT plant was expected to be able to bid into the auction in December 2014. However, it
was concluded that such plant will not be able to be built in time for the first delivery year, resulting in
the aforementioned change to a CCGT plant.
17 Embedded technologies are connected directly with the distribution network, thus they are exempt
from Transmission Network Use of Service (TNUoS) charges, that other bigger projects connected to
the transmission Network are charged.
18
CONE estimations, due to low cost new supply entries in the market, such as
Demand Side Response and net imports (The Brattle Group 2013).
For the
calculation of the missing money, investors would consider among others, the
expected cost of plant emissions, so a low emissions plant would have a cost
advantage over a more-polluting plant, if emissions are correctly priced (CRA 2013).
Net-CONE calculation is subject to large uncertainties and different risks depending
on whether this level is under or overestimated. According with DECC if net-CONE is
underestimated, supply may be discouraged to bid into the auction (as sufficient
“missing money” cannot be recovered by new entrants). As participants would bid in
at the “true” net-CONE, it is likely that an inefficiently low level of capacity would be
procured at T-4. If net-CONE is overestimated, this could attract excess supply,
which could mean buying extra capacity in T-4 (which may have otherwise been
cheaper in a future T-1 auction). However, in a sufficiently competitive auction, the
influence of net-CONE on auction outcomes is likely to be limited. The clearing price
should be driven down by competing plants.
Demand curve
The demand curve used in the Capacity Market is a downward sloping demand
curve. The slope of the demand curve defines how the capacity level contracted
varies with relation to the price. A sloping demand curve will be set for the auction so
that less capacity is bought if the price is very high. According with DECC (2014) it
moderates the gaming risk and reduce the price effects of withholding capacity by
providing flexibility in the volume to be contracted and by making the capacity price
less sensitive to the amount of capacity offered into the auction.
The downward slopping demand curve is expected to reduce capacity price volatility
in comparison to a vertical demand curve. Either movement away from the target in
a downward slopping demand curve, cause gradual decrease or increase in the
capacity price. On the other hand, by falling short by a small amount of the capacity
target in a vertical demand curve, consumers will need to pay high price (equal to the
price cap) to cover that shortfall. Evidence form ISO-New England support the
above. During the eighth capacity action in New England, and having a vertical
demand curve, the price jumped on the price cap, due to a shortage of supply. Since
then, the demand curve in ISO-NE is formed as a downward demand curve.
19
The slope of the UK demand curve for the T-4 auction, as it illustrated in figure 2
below, lies within 1.5 GW more or less than the capacity target which is the
equivalent de-rated capacity of two average-size CCGT’s (consistent with its
selection as the reference technology of choice for net-CONE). According to DECC
(2014a) it is intended as an anti-gaming measure by limiting the ability of a generator
to withhold capacity and influence the clearing price of the auction. For example, in
the case where the generator could be the one who could set the price (i.e. marginal
bidder), he/she might be willing to take out of the auction one of his/her CMUs
(called “pricing out”) so the generator could get benefited by a higher price for the
rest of his/her CMUs. This is profitable whenever the loss of pricing out units is
compensated by higher revenues on the CMUs still in the auction. If a bidder can
realise if he/she is the marginal bidder or not depends on the information, he/she has
from the auction. If less information is provided to the bidders during the auction,
then gaming opportunities are restricted.
As it is illustrated in the graph below, the demand curve for capacity is downward
sloping as suggested from economic theory. The reference point C is the point
where the net-CONE intersects the capacity needed to be auctioned so the reliability
criteria will be met. The second reference point, D, indicates the level of excess
capacity at which customers would be willing to buy additional capacity only if the
price is zero. The line segments BC (capacity below target) and CD (capacity above
the target) indicate that the price reduces as capacity increases. The straight line AB
defines the price cap for the auction (DECC 2014a).
20
Figure 2: Illustrative demand curve for the delivery year 2018/19
Source: Data from DECC and National Grid
The demand curve should send a price signal to participants when the market needs
new capacity, indicating that, when the capacity in the market drops below the target,
investment in the reference technology can be profitable (price and capacity of the
auction more likely on BC line segment). On the other hand, when capacity in the
market exceeds the target, price drops, indicating that new investment in the
reference technology is not going to be profitable. In this case even some existing
participants might need to exit the market when the price reduces below the
minimum price they are willing to accept for their CMUs (price and capacity of the
auction more likely on CD line segment) (FERC 2013).
Price Cap
The auction price cap determines the maximum price at which no more capacity will
be auctioned and it is basically the price at which the auction starts (DECC 2014e).
The price cap is essential to protect consumers from problems such as lack of
competition or gaming incentives if it set at the “appropriate level”. According with
analysis contacted by DECC (2013a) , although a very high starting price is likely to
increase capacity participation in the auction, it poses the risk of a poor and
expensive outcome if collusion is observed or if there is less supply than demand in
the market. On the other hand, a low starting price possible lowers the expected
cost of buying capacity but at the same time it may discourage some bidders from
participating in the auction, resulting in less competition and driving the prices up.
21
With limited competition, the product is likely to be traded at high price even at the
price cap. In addition, a low price cap might limit the incentives to participate in the
action. Hence, the trade-off between the number of bidders and the price cap is very
important because “one additional bidder is more valuable to the auctioneer than a
lower starting price” (Maurer, Barroso 2011). For the first two auctions is determined
as a multiple of 150% of the net-CONE (rounded up). In the Capacity Market in NewEngland is equal to 160% of net-CONE and in PJM 150% of net-CONE.
4.2.2 Price Taker Threshold
Another measure to mitigate gaming and market power opportunities in the auction
is the separation of the bidders as price takers (who cannot set the price) or price
makers (who can set the price). Price takers are permitted to exit the auction only
when the auction price falls at or below the “price taker threshold”. Existing plants by
default are price takers. If the bidders are successful in the auction, they will be
awarded a capacity agreement with a one-year duration at the auction clearing price
(DECC 2016b).
The price taker threshold has been introduced since existing plants might have
already covered the majority (or the total) of their sunk costs and thus have lower
costs than new entry, such as the existing old nuclear plants. Especially during years
where new entry might not be needed, DECC (2014a) supports that existing plants
might exercise market power and seek a higher price. Conversely, some bidders
with existing plants will need to bid higher prices due to high missing money such as
the coal plants. Therefore, the threshold has been set at a level low enough to
mitigate gaming risk, while being at a level that captures the majority of the existing
plant. The price taker threshold for the first two auction in 2014 has been set at 50%
of net-CONE (rounded up). DECC’s modelling (2014a) suggests that 80% of existing
plants would have costs below this threshold.
Existing plants are by default price takers, however, an existing plant has the choice
to enter the Capacity Market as a price maker and set the exit price above the price
threshold, providing cost justification of why the higher price is needed. New entry
and refurbishment generating plants and DSR providers are awarded as price
makers and will be able to bid up and below the auction price cap.
22
The total amount of capacity belonging to price takers in comparison to the capacity
target, is expected to alter the outcome of the auction. Some conclusions about how
the outcome can be changed under different cases could be drawn. Firstly, if the
capacity of the price takers is more than the target, as it is illustrated graphically in
figure 3, then the price of the auction will probably be below the price-taker threshold
(depending on the Net Welfare Algorithm). No new capacity should be among the
winners of the auction, since a new generating plant more likely needs much higher
price to be profitable. Figure 3 shows an example of market outcome and thus, how
the supply curve could look like after the end of the auction when price-takers’
capacity is more than the capacity target.
Figure 3: Possible market outcome when capacity of price-takers is more than
the capacity target
On the other hand, if the amount of capacity belonging to price takers is less than the
target, then the price of the auction will probably be higher than the price taker
threshold. In this case, the exact amount of new capacity will be altered based on the
amount of existing capacity in the market. If the existing capacity in the auction falls
short, i.e. it is less than the target capacity, it is expected that new capacity would be
procured. The type of new capacity in the market will more likely determine the price
of the auction. Alternatively, if the existing capacity is abundant, i.e. more than the
23
capacity target, (but some of the existing capacity procures as price-makers so that
the capacity of price-takers is still below the capacity target) no new capacity is
expected in the market. However, the exact capacity and price is finalised by the
costs of the resources and the bidding behaviour of the participants.
Figure 4: Possible market outcome when both capacity of price-takers and
capacity of existing resources is less than the capacity target
Generally, there is uncertainty around the bidding behaviour of the participants and
thus, the technology mix that will come forward through the Capacity Market.
However, DECC (2013a) supports that the mechanism design should ensure that the
market has optimal incentives to bring forward an efficient plant mix.
In the next section, the results of the two previous capacity auctions will be
presented identifying if the results fulfil the objectives of the Government.
5 Capacity Auction results
In this section the results of the Capacity Auction held in 2014 (National Grid 2015b)
and the Capacity Auction held in 2015 are presented (National Grid 2015c). This part
of the paper compares the objectives of the government with the results and turns to
24
a critique on some of the elements of the Capacity Market. It is based on our
interpretation of publicly available information.
Overview of the Capacity Auction results
UK’s first electricity auction was held in December 2014 for delivery in 2018/19 and
procured 49.3GW of capacity at a price of £19.40kW/year – much lower than the
pre-auction estimations. This will result in total payments for this capacity of £956
million in 2018/19 (2012 prices). New plants with just over 2.6GW capacity secured
capacity agreements, including one new large combined-cycle gas turbine (CCGT)
plant of 1.6GW (Trafford CCGT project) and 0.9 GW of smaller scale diesel peaking
plants.
Almost 19% of the capacity awarded in the capacity auction comes from coal
amounting to total payments of £173 million for 2018/19 and £293 million over the
lifetime of the contracts. All existing nuclear power stations also received contracts
amounting to total payments of £153 million in 2018/19. Although DSR, is more cost
efficient than building a new power station, only 174MW (1 per cent) was procured
for 2018/19 in the auction.
Second Capacity Auction was held in December 2015 for delivery in 2019/20 and
procured 46.4GW of capacity at a price of £18/kW/year, even lower than the
previous auction. This will result in total payments for this capacity of £834million in
2019/20 (2014/15 prices). New small diesel fuel plants with just below 2GW capacity
secured capacity agreements worth £176 million. Only one planned new gas CCGT
plant of 880MW, Carrongton station, received a one-year contract, although it was
eligible for up to 15 year contract.
Almost 10% of the capacity awarded in the capacity auction comes from coal
(4.4.GW) bringing the total cost for coal to 139 million for 2019/20 (including the
contracts awarded in auction 2014). Again all the nuclear stations that participated
in the auction received capacity agreements and their total costs is £139 million.
Is the Capacity Market operating as it was supposing to?
In this part the outcomes of the Capacity Auctions will be evaluated in relation to the
objectives of the Capacity Market as stated in DECC’s Impact Assessment. The
objectives are the security of supply, by incentivise sufficient investment in
25
resources, implementing the changes at minimum cost to consumers and
complement the decarbonisation of the energy sector. To these three initial
objectives it can be added the aim of delivery new efficient gas capacity. On 7th of
January 2016, Andrea Keadsomm, minister of state at DECC, stated that “We are
reviewing the capacity market to make sure we bring on new gas”.
Security of supply
At least one large power plant (fiddlers Derry coal fired station) that has already been
awarded a capacity agreement for 2018/19 has announced that it will close in 2016.
It will have to pay penalties for failing to deliver its capacity obligation but this might
be less expensive than remaining open and running at cost. Moreover, the new
CCGT Trafford plant that has a capacity agreement for 2018/19, did not manage to
secure any investment and it is unlikely to be ready for that delivery year. This plant
accepted a very low price in the auction, less than half of is assumed Net-CONE.
Despite the termination fees already in place, capacity providers in the cases
mentioned above have viewed their capacity obligations as low-cost options and
decided to renege on their commitments. The government has recently introduced
tougher termination fees for failing to deliver new capacity on time.
A number of plant who missed out a capacity agreement in Capacity Auction 2014,
have already closed or have announced closure. In addition, National Grid uses the
Contingency Balancing Reserve (CBR) to balance the system till the Capacity
Market is in place. However, in recent years, it was noticed a big increase in this
reserve capacity, increasing the fear of causing distortions to the market.
As a
result, the Government has announced early implementation for the Capacity Market
to support existing plants and at the same time replace the CBR. More particularly, a
Capacity Auction is to be held in January 2017 in order to remunerate plants in 201718 (DECC 2016a).
Fossil fuel prices have dropped significantly and weighed heavily on wholesale
power prices, having a significant effect on the profitability of both coal and gas
plants, particularly the former. This has triggered announced intentions to close
earlier than expected, increasing risks to security of supply in 2017/18. Bringing
forward the first year of the capacity market by holding an early Capacity Auction for
delivery in 2017/18 will help to address these risks.
26
The Government has consulted more changes and decided to increase the amount
of capacity to being procured at least by 3GW. By increasing the capacity target, the
Government aims at higher probability to attract new gas efficient capacity. However,
there is no guarantee of this, as existing coal plants could receive payments instead.
One of the possible reasons that the Capacity Market did not attract new efficient
gas plants might be that the existing capacity, i.e. the total capacity that prequalified
only as existing or as refurbishing and pre-refurbishing/existing at the same time, is
more than enough to cover the peak demand four years ahead. As it was already
mentioned the refurbishing plants have the choice to prequalify as refurbishing only,
or for both their refurbishment and pre-refurbishment stage. The latter case gives the
opportunity to participants in the auction with a refurbishing plant to exit the auction
when the price reach to the minimum price they would like to accept for their
refurbishing plant and re-enter the auction with the pre-refurbishment stage of the
plant (i.e. existing plant) for which they are willing to accept a lower price. Moreover,
small scale diesel peaking plants are cheaper to operate than new gas plants
therefore, investors prefer the formal type of plant to invest to.
Unfortunately, the exact influence of the price-taker threshold cannot be drawn from
the results, since the information about the status of the participant as price-taker or
price-maker is not available to the public 18 (DECC 2016b).
Value for money
In both Capacity Auctions the clearing price was very low. However, it is clear that
many plants that could remain on the system with no or very small capacity payment
(e.g. nuclear plants) are receiving a windfall. Nearly a third of the existing plants did
not place an exit bid before the auction finished. In addition, capacity payments
seem to work against the carbon price floor (CPF) policy, which sets a minimum
price for carbon emissions produced in electricity generation. The CPF together with
the EU emissions trading scheme, is designed to disincentives fossil fuel generation,
such as coal to stay online. On the other hand, capacity payments are designed to
incentivise generators to stay online. Carbon-intensive plants are penalised and
subsidised at the same time and consumers are called to pay for both.
18
For more information look at rule 7.6 from the Capacity Market Rules document.
27
Decarbonisation
The results of the Capacity Auctions showed that the Capacity Market is not
compatible with the decarbonisation targets of the power sector, because except
from subsidising coal plants, it has also opened the market for carbon intensive
generation such as diesel. This is more likely because the small embedded
generating units are not subject to a number of environmental regulations that affect
larger generators. DECC has recommended to take measures from 2019 to restrict
small generating units using air pollution regulations.
6 Conclusion
This paper provides a description of how the Capacity Market in the UK operates
and what are the emerging issues with its current structure. Capacity Market has
implemented in the UK to address the missing money problem of the energy-only
market and reassure security of supply; one of the Government’s principal goals. At
the same time, it should be aligned with the goals of affordability to the consumers
and decarbonisation of the energy sector.
Although the competition in the auction should drive the costs of the Capacity Market
to the minimum, Capacity Auction is thought to be vulnerable to gaming opportunities
and participants might be able to exercise market power and drive the price of the
auction above the competitive levels. As a result several mechanisms, such as the
price cap, the sloped demand curve, the price-taker threshold, the information
revealed policy have been included in the design of the Capacity Market, to mitigate
market power opportunities and reassure minimum cost to the consumers.
Based on the results of the two previous auctions, it can be concluded that the
current Capacity Market scheme does not fulfil the objectives of the Government and
thus, changes have been proposed by DECC in order to deal with some of these
problems. The Capacity Market has failed to attract any new efficient gas plants and
it is paying coal to stay open longer that it would have otherwise, despite
governments pledge to phase out coal generation. As it is noticed Capacity Market
will result in payments to capacity providers of billions of pounds in the coming years.
These costs will flow from suppliers to providers of capacity and will be passed
28
through to consumers’ bills. Hence, it is important that the auction procures the
required capacity at the lowest possible costs.
The detailed design of the Capacity Market is important in terms of determining how
well this new market works. The new Capacity Market and its implications should be
monitored closely especially during the first years of implementation. Analyses of
proposed or current modifications of the design of UK electricity markets has the
potential to improve understanding of the impacts of proposals on market design and
identify unintended consequences of such policy interventions before they cause
serious problems.
29
APPENDICES
Appendice I
Figure 1: Merit order of UK power generation mix (31 October 2013)
Source: Competition and Markets Authority- Final Report (CMA 2016a)
Figure 1 illustrates the UK power supply curve for 31 October 2013. It shows nuclear
and renewables running at baseload – very low or zero operating cost. (In the case
of renewables earning Renewable Obligation Certificates (ROCs) 19, negative
operating costs come when not producing which entails the loss of the ROC
subsidy). Next in the merit order is biomass and interconnectors. Biomass owners
avoid purchasing EU carbon emissions 20 or paying for the carbon price floor 21. As a
result, biomass is more competitive than coal which comes next in the merit order. In
this figure the pumped storage is placed at the end of the CCGT plants. Approaches
to modelling pumped storage vary. The minimum summer demand in 2013 was
21GW. Generally the merit order varies season by season, day by day and hour by
hour.
19
The Renewables Obligation (RO) is one of the main support mechanisms for large-scale renewable
electricity projects in the UK.
20 More information about EU carbon emission allowances and more general about EU Emissions
Trading System at http://ec.europa.eu/clima/policies/ets/index_en.htm
21
More
information
about
the
carbon
price
floor
at
https://www.gov.uk/government/publications/excise-notice-ccl16-a-guide-to-carbon-price-floor/excisenotice-ccl16-a-guide-to-carbon-price-floor#general-information-about-the-cpf
30
Appendice II
Figure 2: Range of Capacity Remuneration Mechanisms (CRMs)
Source: Agency for the Cooperation of Energy Regulators – Capacity Remuneration
Mechanisms (ACER 2013)
Appendice III
Clearing price
All the exit bids made in the Clearing Round are known as Relevant Exit Bids. In the
T-4 Capacity Auction 2014, the Relevant Exit Bids are ranked first by price (lowest to
highest), then by amount of capacity offered (highest to lowest) and then by the
duration of agreement (lowest to highest) and lastly by lottery via a random number
(lowest to highest). In the case of a tie, the system will use the ranking above to
decide which plant is eligible for an agreement (National Grid 2014).
In the Clearing round, the system will first calculate the total amount of capacity of all
plants which have not exited the auction. After that, the system will “work backwards
up the supply curve to add back the Relevant Exit Bids” based on the ranking
explained above (highest ranking to lowest ranking). In this way the system will
determine if there is an Exact Match between the supply curve and the demand
curve. In the case of Exact Match, the Relevant Exit Bid that caused the exact
match would set the Clearing Price and the capacity of the auction.
31
Figure 3: Exact Match
Source: National Gird (2014)
Figure 3 provides an example of Exact Match. The total capacity of all plants that
have not yet exited the auction is 500MW and it is illustrated on the graph by the
yellow dot. This is also the starting point for the calculation of the Clearing Price.
Firstly, the highest ranked bid, i.e. point 1, is added back to the total capacity. At this
point the supply curve does not intersect with demand curve. Relevant Exit Bids
continue to be added back until an Exit Match is established or until supply curve has
met the demand curve and no exact match has been identified. Secondly, the next
highest ranked Relevant Exit Bid (i.e. point 2) is added back and at that point the
supply curve meets the demand curve and hence an Exact Match has been found.
On the other hand, when there is no exact match, the Clearing price and capacity will
be calculated using the Net Welfare Algorithm (NWA).
32
Figure 4: Net Welfare Algorithm (a)
Source: National Gird (2014)
Figure 4 illustrates an example with no Exact Match. As before the starting point is
the yellow dot and at point 1 supply does not meet demand therefore the next
Relevant Exit bids are added back according to the ranking order. By adding back
the second highest ranked point (i.e. point 2), the supply curve crosses the demand
curve in an intermediate point between Relevant Exit Bids 1 and 2, thus no exact
match can be determined. Consequently, the Clearing Price and the capacity are
determined by the NWA.
Basically NWA evaluates if over procuring or under procuring capacity would be
most economically beneficial for the consumer (National Grid 2014).
𝑄𝑄ℎ
� 𝑃𝑃(𝑄𝑄)𝑑𝑑𝑑𝑑 − (𝑃𝑃ℎ × 𝑄𝑄ℎ − 𝑃𝑃𝑙𝑙 × 𝑄𝑄𝑙𝑙 )
Where:
•
𝑄𝑄𝑙𝑙
Ph is the Exit Price of the Relevant Exit Bid that is above the demand curve. If
such bid does not exist, Ph must be the Bidding Round Price Cap for the
Clearing Round.
33
•
Pl is the Exit Price of the Relevant Exit Bid that is below the demand curve. If
such bid does not exist Pl must be the Bidding Round Price Floor for the
Clearing Round.
•
Qh is the total capacity of all plants up to and including the highest ranked
Relevant Exit Bid that is above the demand curve. If such bid does not exit,
Qh is the capacity supplied at the Clearing Round Cap.
•
Ql is the total capacity of all plants up to and including the lowest ranked
Relevant Exit Bid that is below the demand curve. If such bid does not exist Ql
is the capacity determined at the Clearing Round Floor.
•
P (Q) represents the Demand Curve as specified by the Secretary of State.
The integral of the demand curve between Ql and Qh, i.e. the area under the demand
curve between the two points, equals the extra benefit to the consumer in clearing at
the quantity Qh rather quantity Ql. This is illustrated by the red shaded area in Figure
5. The difference between PhQh and QlPl gives the extra cost of procuring Qh rather
than Ql as it is shown by blue shaded area in Figure 6.
Figure 5: Net Welfare Algorithm (b)
Source: National Gird (2014)
34
Figure 6: Net Welfare Algorithm (c)
Source: National Gird (2014)
If the result of the Net Welfare Algorithm is positive, it means that the clearing price
and capacity are determined by the plant which submitted a bid just above the
demand curve. If such plant does not exit, the clearing price and capacity will be
determined by the Clearing Round Cap. If the result is negative, it means that the
clearing price and capacity are determined by the plant that submitted a bid just
below the demand curve. If such plant does not exit, the clearing price and capacity
will be determined by the Clearing Round floor. All the plants with Relevant Exit Bid
less than or equal to the clearing price, will be eligible for a capacity agreement
(National Grid 2014).
35
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