Download The Single Electricity Market (SEM) Proposed High Level Design

The Single Electricity Market (SEM)
Proposed High Level Design
31 March 2005
AIP/SEM/06/05
1
Executive Summary
The creation of the Single Electricity Market (“SEM”) will be the first tangible step
towards a seamless energy market on the island of Ireland. This paper which sets
out the high level design of the SEM, is the Regulatory Authorities’ response to the
regulatory tasks set out in the DETI/DCMNR document “All-Island Energy Market, A
Development Framework”.
The SEM is a key part of the all-island energy agenda, and is a wholesale trading
system based on the concept of a gross mandatory pool. This trading vehicle has
been selected for its suitability to the requirements of the market on the island, and in
particular the need to effectively meet increasing demand for electricity while
maintaining security of supply.
This paper details a number of key areas of consideration and has set out the
Regulatory Authorities’ preferred choice of the trading mechanism, which includes;
• capacity payments;
• central commitment;
• price formulation based on an ex-post unconstrained single simple stack with
constrained on and off payments under predefined circumstances;
• shallow generator connection policy;
• locational loss factors; and
• locational use of system charges for generators.
The details of the market model to be implemented are yet to be developed including
the precise nature of capacity payments. This will be undertaken in consultation with
interested parties after the high level market design is determined.
Having examined the available market design options for the SEM, this paper
presents two high level designs for a gross pool market before identifying the
preferred high level design. The two options presented are differentiated by their
approach to unit commitment, price formation and dispatch, and can be broadly
classed as “central commitment” versus “self commitment” models. The question of
explicit capacity payments has been dealt with as a stand-alone issue as either of the
gross pool models could be either energy only or include an explicit capacity
payment mechanism.
This paper outlines the high level principles of each design, and makes particular
reference in the evaluation of the options to the deliverability and suitability of each
variant for the conditions which we face in creating the Single Electricity Market. The
paper concludes that the central commitment variant is most suited to the Single
Electricity Market and proposes that this is taken forward to the detailed design stage
as the basis for the new wholesale trading arrangements.
Structure of this paper:
The remainder of this paper contains the following sections:
Economic Case: An explanation of the economic rationale followed by the Regulatory
Authorities in proposing the SEM design.
Scope and Process: Details of the process and how to respond to this consultation.
2
Market Models: An explanation of the decision to design the market based on a gross
mandatory pool, and the alternative bilateral model which has been examined and
rejected.
Capacity Payments: An outline of the basis for the decision to include an explicit
capacity payment mechanism in the design, and discussion of available options.
Common Design Themes: An analysis of the common themes, which apply in both
market design variants which the paper examines.
The Design Options: Details of the “self” and “central” commitment models, and the
key issues in regard to complexity, deliverability, pricing and dispatch which each
involves.
Evaluation: An analysis of each model, and the grounds for the Regulatory
Authorities’ preference.
Market Accessibility: Outline details of the means by which CHP, renewables and
demand customers may participate in SEM, details of data transparency and the
regulatory approach to market power mitigation.
Conclusion
Appendices: Background detail to the existing markets in each jurisdiction.
3
Contents
Foreword .............................................................................................................6
1 Introduction................................................................................................12
1.1
The Economics of a Single Electricity Market (SEM).......................12
1.2
Scope of this paper..........................................................................14
1.3
Objective of the Single Electricity Market.........................................15
1.4
Process and Timetable ....................................................................16
2 Market Models – Centralised Vs Decentralised Market ..........................18
2.1
Introduction to Market Models .........................................................18
2.2
Decentralised Market – The Bilateral Contract Market Model..........18
2.3
Centralised Market - The Gross Mandatory Pool Model ..................20
2.4
Preferred Market Structure ..............................................................21
3 Capacity Payments....................................................................................22
3.1
Introduction......................................................................................22
3.2
Implicit CPM ....................................................................................23
3.3
Explicit CPM ....................................................................................23
3.4
Conclusion on Preferred CPM .........................................................24
3.5
Criteria for Selection or Design of an Explicit CPM..........................24
3.6
Issues for Consultation ....................................................................25
4 Common Design Themes for the Gross Mandatory Pool.......................27
4.1
Unconstrained Market Clearing Price ..............................................27
4.2
Compensation for adjustments ........................................................27
4.3
Interconnector Trading.....................................................................29
4.4
Locational Signals in the SEM .........................................................29
4.5
Losses .............................................................................................30
4.6
Dispatch and trading periods ...........................................................31
4.7
Ancillary services .............................................................................31
4.8
Market data......................................................................................32
4.9
Conclusion.......................................................................................33
5 SEM Market Model Options.......................................................................34
5.1
Definitions........................................................................................34
5.2
Self-commitment model ...................................................................35
5.3
Central-commitment model..............................................................36
5.4
Conclusion.......................................................................................37
6 Evaluation of Models .................................................................................38
6.1
Evaluation Criteria ...........................................................................38
6.2
Evaluation of Markets – Centralised –v- Decentralised ...................39
6.3
Evaluation of Markets; Self-Commitment –v- Central Commitment.43
6.4
Conclusion.......................................................................................46
7 Market Accessibility ..................................................................................47
7.1
Renewables and CHP .....................................................................47
4
7.2
Emissions trading ............................................................................48
7.3
Demand Side Participation ..............................................................49
7.4
Market Power ..................................................................................49
8 Conclusions ...............................................................................................50
Appendix 1. Existing Markets on the island ...............................................51
Transitional Trading Arrangements in Ireland.............................................51
Current Trading Arrangements in Northern Ireland ....................................52
5
Foreword
The Single Electricity Market: What we are Trying to do and Why
In this document, the Commission for Energy Regulation (CER) and the Northern
Ireland Authority for Energy Regulation (NIAER) are publishing proposals for a single
wholesale market to serve electricity customers wherever they might be in the island
of Ireland.
As part of the European Union, Ireland and Northern Ireland are committed to the
development of a single European electricity market. The European Commission
has put in place an overarching legislative framework within which all member states
are working to achieve the single electricity market which is designed to bring
benefits to all European citizens and to contribute to Europe’s competitiveness.
Within this framework, cross border trading is developing and the interconnectivity of
electricity networks is increasing. Countries that are physically close are developing
closer trading ties. In this environment the island of Ireland faces a unique challenge
and a unique opportunity. On the one hand the island is far less interconnected than
other mainland European jurisdictions but on the other hand, we have the opportunity
to create a single market within the island, realising the benefits of this move for all
consumers of electricity and for the economies north and south. Furthermore, in the
future it may be possible to align the all-island market with the UK market to develop
a British Isles market.
The Nature of Electricity Markets
The nature of product markets differ from one country to another because the laws,
the trading arrangements, the taxation system, the organisation of distribution, the
degree of market concentration, consumer preferences, and so on are different.
These are all artificial differences and over time may change and disappear, or can
be made to disappear. The European Union has to a considerable extent been
driven by a policy agenda, which has included moving towards an ever more
homogeneous marketplace for goods and services right across Europe. Indeed the
same logic has driven the creation of the internal market in electricity.
However, while electricity markets share the same characteristics of other product
markets, they also have more profound marks of differentiation and for that reason
may differ considerably within the European Union’s twenty five Member States.
To a much greater extent than other product markets electricity markets have been
shaped by more elemental forces and for that reason they differ from each other in
much the same ways as countries or regions within countries differ. Geology and
topography have been as important in determining the nature of the electricity market
as geographical, demographic and strategic factors.
A rich endowment in coal bearing seams not only provided some countries with a
secure source of electricity generation but also determined the location within that
country of its power stations. Mountains and lakes ensured that other countries had
access to hydro-electricity. Natural gas offshore provided a different power source.
A concern arising from a paucity of local fuels coupled with a strategic concern for
security have led, as in the case of France, to the nuclear option.
6
Electricity, unlike other energy sources other than gas, can be transported relatively
cheaply over long distances. It was the exigencies of the primary fuel source, which
determined where the electricity was generated. This is as true of fossil fuel based
electricity as of nuclear or renewables. Coal seams, coastal areas for imported coal
and oil, windy areas for wind based generation, access to cooling water for nuclear
and indeed other power stations, mountain valleys or rivers for hydro and even the
distribution of peat bogs became the critical factors in deciding where electricity
would be generated. The location of generation in relation to the electricity load had
other effects e.g., whether a national electricity market would require to be endowed
with an extensive mesh of transmission wires and whether powerful national
institutions would be required to ensure that electricity was provided in a secure and
timely way. Market size has also been a factor as large populations with large
energy requirements could support large generation units that provided economies of
scale.
The Weakening of Determinism
Since gas can be transported more economically than electricity, there has recently
been some relaxation of this rigid determination with gas-fired generation. Other
changes are also weakening the pressure of geographical determinism. Embedded
generation can be produced by local fuels such as biomass and could be located at
weak points in the rural network. Here the direction of determinism could even be
reversed and the opportunities provided by the system could create a market
opportunity for producing a fuel based on an energy crop grown locally. Similarly
population centres, which by their very nature produce large volumes of combustible
waste, could both provide a location for generation as well as the fuel for that
generation. Moreover it seems likely that, with the merging of energy efficiency,
construction industry and micro renewable technologies, a decreasing proportion of
the electricity requirements of buildings will in future be imported from electricity
grids.
But the gas exception and the other small scale factors – which in practice are
unlikely to make a substantial impact for at least another decade - should not blind us
to the need to recognise the particular characteristics of each electricity market and
the need to create a market structure which works in the circumstances with which
we have to contend.
Divergent Electricity Markets in the British Isles
The experiences within the islands of Great Britain and Ireland have been rather
different. England, Wales and Scotland were all generously endowed with coal.
Scotland in addition has secured a significant proportion of its electricity from the
large-scale hydro plants built in the Highlands – mainly in the 1950s. More recently
all of Great Britain has benefited from North Sea natural gas. Given its historic
position as a major military and industrial power in the middle years of the last
century Great Britain also developed a nuclear industry which – even if in decline –
accounts for over 20% of its electricity and does so in a carbon neutral way.
Ireland did not have any coal at the time when coal was the dominant primary fuel
and initially developed its electricity using hydropower subsequently supplementing
that with the only other indigenous power source – peat. Later on gas was found off
its coast. Northern Ireland has always been the least favoured region, having no
indigenous resources of its own – at least none which were identified at a time when
they might have been usefully exploited. It derived no benefit from the rest of the
7
UK’s natural resources or nuclear power and functioned as an electricity island until
very recently.
Changing circumstances have eroded the differences between Northern Ireland’s
and Ireland’s electricity markets. Ireland’s hydro resource has simply been
overwhelmed by rising demand and peat is both declining and ceasing to be a viable
option socially, economically or environmentally. The construction of gas pipelines
which link both parts of the island to Great Britain and which will link both parts of the
island of Ireland in 2006 serve to make the Ireland’s gas supply part of a common
resource.
Despite these rather different experiences, Northern Ireland and Ireland have begun
to develop very similar electricity market characteristics. They have in common a
paucity of fossil fuels, a geographical position at the end of Western Europe’s gas
supply chain from Russia or North Africa, a lack of gas importing capacity in the form
of LNG facilities, strong demand growth, a large carbon emissions co-efficient, a
concentration of load in two east coast areas but with very extensive rural “tails”
resulting in a long line length per customer, and a better than EU average renewable
potential. Such minimal interconnection as they have with neighbouring electricity
markets is, in practice, shared through the Moyle interconnector with Scotland.
Even without the stimulus of the European Union’s Internal Energy Market Directives,
the changing nature of the way in which electricity is produced and the growing
concern for security and the environment would be driving both parts of the island to
exploit the opportunities for meeting their requirements for electricity more
economically by solving problems together instead of separately.
Speed and Scale of the Growth of Cross Border Trade in Electricity
Ten years ago not a single kilowatt-hour (kWh) of electricity flowed across the border
between Ireland and Northern Ireland. For the four years after interconnection was
re-established in 1996 flows were limited to those arranged between the two
transmission system operators (TSO) for system stability reasons or to provide some
marginal trades, and rescue flows.
It is salutary to consider what has been accomplished in the five years since the first
units of electricity where traded commercially across the border on the 19th of
February 2000.
Since that date four major companies have invested hundreds of millions of
pounds/euro in new plant and infrastructure on the other side of the border from their
“home” territory. In these few years Bord Gais Éireann (BGÉ) has built a gas pipeline
from Carrickfergus to Coolkeeragh and is preparing to build a transmission pipeline
connecting the Northern Ireland system to the Irish Republic’s and also to develop
distribution businesses in ten towns in Northern Ireland. The Electricity Supply Board
(ESB) and Viridian have each built a new power station across the border from their
home base. Airtricity have built two wind farms in Northern Ireland and one that,
while it is located in Ireland, is connected to the Northern Ireland grid. More wind
farms will be built just as soon as they receive planning permission. As well as
investing in infrastructure these companies have also invested heavily in the people
and systems that they need to build up the customer base which they both need to
secure “across the border”. ESB Independent Energy (ESBIE) is the largest second
tier supplier in Northern Ireland and Energia holds an identical position in Ireland.
Airtricity is the largest supplier of green electricity in both markets. Clearly all the
8
major companies on the island concerned with the generation and sale of electricity
regard the island as a single field of operations.
Equally clearly those who did not already have a stake in the electricity market in
either part of Ireland have not been drawn to the island as a market in which to do
business. Companies from Great Britain Power showed some interest in Northern
Ireland in the early years of market opening. Scottish Power and Powergen were
both significant players in the early days of market opening in Northern Ireland.
Despite the potential advantages to British based companies that it might have been
expected would flow from the Moyle interconnector there is currently no significant
interest from companies based in Great Britain in the Northern Ireland market.
Similarly in the market in Ireland despite significant growth in electricity consumption,
investment has been slow in materialising. While it has attracted Epower, DUKE,
Eon, RWE, Aughinish Alumina and Tynagh Energy Ltd to the market, investment has
had to be induced on occasion arising from concerns for security of supply.
The cross border investment has been accompanied by a growing amount of cross
border trade in electricity. Sequentially the development of the renewables market in
both jurisdictions was facilitated by cross border energy flows. Firstly the Irish market
imported for a critical market-testing period the output of Northern Ireland’s Non
Fossil Fuel Obligation wind farms until other sources of renewable electricity became
available to meet the established demand. More recently green suppliers in Northern
Ireland have been able to grow the green market in Northern Ireland by importing
from the south as demand for green electricity in Northern Ireland has grown at a
faster rate than the supply of green sources of generation.
Last year 1.40 terawatt-hour (TWh) flowed across the interconnector. This year the
figure is expected to be 1.65 TWh. In 2005/6 it is expected to be 2.63 TWh. This will
mean that approximately 10% of all the electricity consumed in Ireland will have been
imported from or through Northern Ireland.
It is now clear that the limiting factor on cross border electricity flows is the capacity
of the networks to handle the energy flows which could take place - a situation which
will take time to remedy.
The amount of electricity that flows across the border is now at the physical limits of
the system to carry it. The amount traded across the border – thanks to a trading
mechanism known a super-position, which in effect allows market participants to
match imports and exports to ensure that both trades are permitted – exceeds the
amount which is carried. Customers in both jurisdictions now enjoy electricity at
lower costs than they otherwise would. There are other benefits too, such as lower
reserve costs and the fact that the cost of the Moyle interconnector is not borne
solely by customers in Northern Ireland.
It is difficult to place a definitive value on the cross border electricity market that has
developed to date. The 1.65 TWh which are expected to flow across the border will
produce a saving of around 0.5p/0.57c per kWh to customers in Ireland and make a
0.5p/0.75c contribution to fixed costs in Northern Ireland are worth
stg£16.5m/€37.2m a year in customer savings.
9
Organic Market Integration
This paper on the design of the SEM sets out the next stage in what is clearly an
organic growth in market integration. The single wholesale market is not a construct
being imposed on either customers or the electricity industry on the island. It is
simply the logical next step in removing the next set of barriers to competitive prices
and quality service for customers. It will do so by establishing a trading mechanism
that enables us to share more efficiently the opportunities we have to produce and
supply electricity to customers wherever they are on the island. As we face common
problems we can solve them at lower cost by sharing the solutions.
This is not a final step. It would be logical to have other steps, which will follow in
due course to deliver yet further benefits to customers. Planning together the
removal of transmission constraints is an obvious candidate for action once
agreement is secured on the shape, design and management of a single wholesale
market. The important point though is that there is no grand design to be imposed on
this market irrespective of cost or the evidence which the market itself produces of
what – if any – should be the next stage of development in its evolution. Customers
and the market players themselves will have a major impact on that evolution both by
what they say and what they do. It is after all market players which have by their
behaviour produced the remarkable transformation of the island’s energy scene over
the very few years which have elapsed since the Internal Market Directive took effect
in Ireland in 2000. It is they who will be the drivers in the future.
Ensuring a Strategic Framework for a Liberalised Market
The energy markets for the next twenty years are likely to be dominated by concerns
about security and the environment as well as by more traditional economic concerns
of cost and regional competitiveness and the way in which all these concerns may be
tied together and delivered in a fully liberalised market. It is fair to say that policy
makers across the European Union are only now beginning to grapple with an energy
policy agenda which is more multi-faceted than that faced by previous generations of
policy makers. While there is much commonalty between the problems faced by all
energy policy makers, the solutions will not be the same everywhere. Broad
principles will be the same but the specific set of solutions adopted in one area of
Europe may differ from those adopted in another.
The European Union’s approach is a mixture of regulation and liberalisation.
Member states are increasingly subject to standards and requirements – for example
with regard to the energy efficiency of buildings or the percentage of electricity to be
produced from renewables or the amount of C02 that may be emitted. Within this
high level framework much may be delivered through market mechanisms, fiscal
measures and financial instruments as well as through standards and regulations.
Since both parts of Ireland face similar risks and have similar resources and
opportunities as well as similar economic and social characteristics it would be to our
mutual advantage to come up with common solutions where we can pool resources
and achieve some economies of scale.
Accordingly the market design that we agree on should not set up obstacles or
frustrate in any way the delivery of the wider energy agenda with its need to meet
security of supply and environmental concerns. The market structure must therefore
work for all technologies including renewables and Combined Heat and Power. It
must facilitate embedded generation and the exploitation of renewable resources at
the point where it is most economic to allow them to produce electricity. It must not,
in the limited interest of an efficient electricity structure impose external costs on
10
other parts of the economy. This may be difficult to achieve. It would be easy to fall
in with the assumption that electricity markets must continue to grow exponentially
and it may require care and foresight to construct a market where ever tightening
environmental constraints and security concerns, and not demand growth alone, are
the drivers for new investment.
Adding to net wealth
Since the industrial revolution Northern Ireland has been a price taker as far as its
energy requirements have been concerned. The primary fuels were imported and
almost all of the hardware used to convert them into useful energy and transport
them was also imported. Ireland fared better but has never approached selfsufficiency in energy supply.
The security of supply and the environmental agenda do to some extent converge
insofar as a reduced energy requirement through energy efficiency and an increased
use of renewable energy will improve security of supply. They may also improve the
contribution of energy expenditure to the local economy. The ability of the energy
sector to contribute to the national economy is obvious. This is the case with
countries well endowed with fossil fuels but has also been seized upon by countries
determined to develop a manufacturing base in energy technology. The Renewable
Obligation regime that applies in Great Britain relies for much of its rationale on the
scope for creating a market for a renewables manufacturing industry, which can then
be exported. The SEM should be judged not only by the extent to which it reduces
the cost of electricity used by customers in both parts of Ireland but also by the extent
to which it reduces energy expenditure in its totality.
Clearly the single wholesale market in electricity will have wide economic implications
for the entire island.
Conclusion
The proposal to create a single wholesale market for electricity should not be
regarded as surprising or radical. It is simply the logical next step in responding to
the preferences of customers and market participants. Those preferences have been
demonstrated by the way in which they made the island a single electricity business
area in just four years. In that time the industry’s achievement has been immense.
There is now a need to plan the next steps and do so in ways which build on the
specific characteristics and energy needs of customers in both parts of Ireland, which
add to the net wealth of the people of the entire island and which will facilitate wider
security of supply and environmental concerns and obligations.
It is in this context that we invite the electricity supply industry, its customers and
anyone interested in public policy issues to consider with us these accompanying
proposals for creating a single wholesale electricity market.
11
1
Introduction
1.1 The Economics of a Single Electricity Market (SEM)
The SEM is being designed to create a new single market for the wholesale trading
of electricity on the island of Ireland and Northern Ireland thereby bringing together
the two existing wholesale markets on the island. The new single market must be
tested on the basis that over the life of the market design electricity consumers in
both jurisdictions should be better off than they would have been in separate
markets, which merely traded with each other.
The benefits which can be gained from an effectively functioning SEM will include the
following:
• More efficient generation dispatch, leading to lower cost of generation;
• A larger single wholesale market, facilitating greater economies of scale and
scope;
• Energy prices set competitively;
• Predictable and Stable trading system;
• Increased attractiveness for generation investment and supplier entry;
• Increased security of supply;
• Integrated system planning leading to more robust infrastructure on the
island; and
• Shared costs of maintaining fuel diversity.
The single market will establish a mechanism that will permit the most efficient
dispatch of generation plant on the island. At present, both transmission system
operators (TSOs) dispatch independently, but take advantage of opportunities to
reduce overall island system costs through trading, where available. The existing
interconnector (“the North-South interconnector”) on the island is available for third
party trading and the combined effect of market and TSO trades captures some
element of efficient dispatch. It is anticipated that additional savings will be gained by
a single economic dispatch.
It is important to note that the North-South interconnector is heavily used at present
and the predominant direction of flow is North-South. The Regulatory Authorities and
TSOs have developed a superposition system (“paper trades”) to allow energy trades
to take place to the maximum extent within the physical constraints imposed by the
capacity of the North-South interconnector. Under the SEM, the North-South
interconnector will be treated as a transmission line and the system will be
dispatched accordingly. This may allow for increased energy flows across the link at
certain times of the day and year, by comparison with the existing position.
The expected savings from a single joint dispatch should accrue from increased
dispatch of cheaper “base-load” plant (mainly in the north) and lower running of more
expensive plant (mainly in the south). The cost of maintaining system reserves
should also fall since reserve will be treated as a single island resource and should
be managed more dynamically. At present the reserve is split between both
jurisdictions on an agreed basis.
ESB, in its response to the consultation exercise carried out by DETI and DCMNR
(the relevant Government Departments in each jurisdiction) last year concerning the
12
all island market, referred to potential savings in capacity and fuel from a single
dispatch in the island. The ESB concluded that these savings might amount to
between €21 million and €36 million per annum, of which the most significant
element is a fuel benefit from increased dispatch efficiency. These estimates are
broadly in line with information available to the Regulatory Authorities on the basis of
studies previously carried out by the TSOs.
The Regulatory Authorities and the Departments support the case for further
interconnection on the island to maximise the benefits of integration of the markets.
Interconnector capacity is limited at present, with the majority of the flow being North
to South, although superpositioning allows contractual flows to exceed physical
flows. It is the intent of the Regulatory Authorities to explore with the TSOs and
asset owners the most economic means of increasing cross border capacity,
including the construction of a second interconnector. In the SEM, such an
investment would be a transmission line and not an interconnector, and its capacity
will be rationed not by explicit auction but by the normal constraint rules which will
apply to generation and transmission dispatch on the island as a whole.
An all-island electricity market will have around 2.5 million electricity customers (1.8
million in Ireland, 0.7 million in Northern Ireland). While this is small in the EU
context, it is still a considerably larger market than the two single markets operating
independently, and should provide a much-improved base for the entry of new
market participants, both generators and suppliers. This market dynamic should also
serve to increase the competitive pressure on prices while providing some
economies of scale for market participants. It is worth recognising that the number of
consumers on the island is comparable to the customer bases of some British based
supply companies. Bearing this in mind it should not however be taken to mean that
the island supply market is too small to attract new suppliers, as we are mindful that
margins are a factor of not only input costs but of the cost to participate. It is the
express intent of the Regulatory Authorities that we implement an effective market at
least cost to all consumers and participants over the longer term.
A single market will also lead to a reduced duplication of functions thereby realising
cost savings. For example, in the SEM a single wholesale market relieves those
participants who presently trade in both separate markets of the need to maintain two
separate bulk power buying functions.
The creation of a gross mandatory pool, where economic rationale suggests that
bidding takes place at marginal cost, will also serve to deliver efficient price
formation. Competition between generators for dispatch, combined with a financial
contracts market with suppliers, should, all other things being equal, lead to lowest
cost production.
The development of a single market with a clearly defined and stable trading
mechanism, through the gross mandatory pool, will also serve to boost investor
confidence. A market that is properly established and which is designed to remain in
operation for a significant period of time, with rules and oversight that are clearly
defined, will allow investors to properly assess the risks and rewards of investing. A
trading arrangement where price signals and forward markets, where they develop,
will communicate the need for new investment should also allow for efficient and
timely new generation build. Equally, suppliers who see a stable market, and
particularly a gross mandatory pool, should face fewer difficulties to enter the market
due to ease of access, when compared to a bilateral contract regime. Supply
competition will also be enhanced by the larger total market size, and the economies
of scale that this implies.
13
The strategic benefits for the island in terms of increased market size, shared reserve
costs, shared fuel diversity costs, the increased competitive dynamic and the
expected boost to investor confidence are significant. It is important to recognise that
these benefits, in an immediate financial sense, are likely to be of the order of €21-35
million per annum. With this in mind the Regulatory Authorities have taken the view
that a market design which is complex and which requires significant participant
costs (both of an initial and ongoing nature) is likely to erode consumer benefit. The
design solutions proposed in this paper are therefore predicated on deliverability
within the stated timeframe and at least cost, consistent with giving effect to a
functioning sustainable market.
The Regulatory Authorities conclude that the SEM will deliver a new, larger and more
competitive market, which should lead to a more efficient allocation and use of
resources, delivering lower prices to consumers in the longer run. The economic
benefits of the market will also be felt in terms of an improved climate for investment
and market entry.
1.2 Scope of this paper
This paper presents a high level design for the implementation of new wholesale
electricity trading arrangements for the island. Following consultation with industry
participants and interested parties, the Regulatory Authorities have evaluated various
options for the market and this paper outlines their preference for a particular market
model and requests further comments and input. Throughout this process the
Regulatory Authorities have been mindful of the stated objective of the new
arrangements and their duty to final customers.
Other areas of work referenced in the Memorandum of Understanding between CER
and NIAER (August 2004) and highlighted in the All-Island Energy Market
Development Framework will be progressed in tandem with work on the SEM but are
outside the immediate scope of the SEM and are therefore not addressed in this
paper. The Regulatory Authorities will provide regular updates to industry on
progress in relation to these issues and where appropriate, consultation will occur. In
addition, the Regulatory Authorities will update the DCMNR and DETI on overall
progress on the all-island energy market via the Joint Steering Group (JSG). Both
DCMNR and DETI will have to progress the legislative issues to support the Energy
Market Development Framework in order to enable implementation of all aspects of
the all island market. Again legislative issues are not dealt with in this paper as they
are outside the scope of market design and indeed outside the responsibility of the
Regulatory Authorities.
However, the Regulatory Authorities recognise the
requirement to revise the legislative framework to support the all-island project.
Work on certain issues has already commenced. The CER and NIAER are currently
progressing the issue of modelling and participants will be provided with updates on
this work stream at regular intervals. The management of dominance is being
addressed via a separate consultation process. The Regulatory Authorities are in the
process of reviewing options for the implementation of the SEM with SONI and
ESBNG.
14
1.3 Objective of the Single Electricity Market
The Commission and NIAER, in light of their statutory duties and functions under the
Electricity Regulation Act, 1999, and the Northern Ireland Electricity Order S.I.
1992/231 (‘the Electricity Order’) respectively, and taking into account the spirit of the
Draft Framework published on 22 November 2004, have developed the following
primary objective for the SEM:
“The wholesale electricity trading arrangements should deliver an
efficient level of sustainable prices to all customers, for a supply that is
reliable and secure in both the short and long-run on an all-island basis.”
This primary objective is supplemented by the following five objectives:
•
ensuring a secure supply of electricity;
•
promoting competition in the electricity market;
•
minimising transaction costs for participants and customers;
•
fostering the use of renewable, sustainable or alternative energy sources; and
•
enabling demand side management.
Security of Supply
The new arrangements should serve to deliver efficient and sustainable prices in the
market which should in turn result in efficient consumption and investment decisions
regarding timing of investment and plant type, size and location.
Promotion of Competition
Under competitive market conditions, market prices are set to bring supply and
demand into equilibrium. Prices set this way result in an efficient allocation of
resources. Competition amongst profit maximising market participants incentivises
participants to increase output, reduce costs, and increase availability. The
achievement of the primary objective of the new arrangements as outlined above is
dependent on the promotion of competition.
Minimising Transaction Costs for Participants and Customers
In reviewing the trading arrangements the Regulatory Authorities are mindful of the
transaction cost implications for participants and customers. Therefore, costs
incurred during the implementation of the SEM should be proportionate and no
unnecessary costs should be incurred. Transaction costs for interacting with the
market under the new arrangements should not act as a barrier to participation in the
market.
Fostering Renewables
The Commission, in carrying out its duties under Section 9 of the Electricity
Regulation Act, 1999 (“ERA”) must have regard to the need to promote the use of
renewable, sustainable or alternative forms of energy. NIAER has a duty under the
Electricity Order to have regard in carrying out its functions to the effect on the
environment of activities connected with the generation, transmission or supply of
electricity. Therefore, throughout this review the Regulatory Authorities will be
mindful of the potential impact of any proposed arrangements on renewable energy
producers.
Demand Side Participation
The Regulatory Authorities are of the view that the trading arrangements should
facilitate demand side participation, wherever it is practicable to do. Market prices
should provide signals to which customers can react. Where this occurs the market
15
as a whole should benefit through reductions in prices during peak and customers
should also benefit through profits from the provision of reserves where this is
facilitated.
1.4 Process and Timetable
A series of bilateral meetings were held in autumn 2004 between the Regulatory
Authorities and participants and interested parties from both jurisdictions to discuss
views on the appropriate market model for the SEM. These meetings were informed
by responses to the CER ‘s questionnaire of June 2004 and responses to the NIAER
consultation on ‘The Changing Northern Ireland Generation’ in September 2004.
This afforded parties who had responded to the CER questionnaire and the NIAER
paper the opportunity to build on their initial responses and/or to revise their views,
and also facilitated discussion with parties who had not submitted a response in the
initial stage of the consultation process.
The Regulatory Authorities, having considered the various market models proposed,
made a presentation to a round-table meeting of interested parties on 31st January
2005 in Belfast, at which the Regulatory Authorities noted that there were a number
of issues that required further consideration. Bilateral meetings were subsequently
held between the Regulatory Authorities and interested parties to discuss these
issues further, in particular the issue of capacity payments.
The Regulatory Authorities have carried out an initial evaluation of the market models
formulated following the above consultation and have outlined their preferred market
model in this paper.
The Regulatory Authorities are publishing this paper for consultation for a period of
eight weeks.
•
Written responses to this paper should be submitted to the Regulatory
Authorities (see below) within six weeks by close of business on 13th May
2005.
•
A further two week period up to 27th May 2005 will be reserved for
participants to engage in bilateral meetings with the Regulatory Authorities to
discuss the market model or specific aspects of submissions. The specific
dates for thee bilaterals will be notified to interested parties in early April
2005.
In addition the Regulatory Authorities intend to hold two public workshops, one where
the Regulatory Authorities will discuss their proposed market model and a second
where the Regulatory Authorities will invite parties to make their own presentations
on the SEM high level design. Alternatively; both aspects may be combined in a
single workshop. A decision on this will be taken in early April, depending on the
level of interest, and communicated to interested parties.
The Regulatory Authorities will be adhering strictly to these deadlines. The
Regulatory Authorities will issue a final decision in June 2005 and this will feed into
the SEM rules development process. In reaching a decision on the final design the
Regulatory Authorities will be mindful of the objectives of this review as outlined in
this paper and of the interests of final customers on the island of Ireland.
16
It is anticipated that the Regulatory Authorities will publish some key project
milestones, bearing in mind the legislative timelines, for the implementation of the
SEM with its final decision on this high level design.
Responses should be submitted by 5pm on Friday, 13th May 2005, preferably in
electronic format, to either of the following parties:
Tomás Murray
Commission for Energy Regulation
Plaza House
Belgard Road
Tallaght
Dublin 24
Ireland
[email protected]
Donna Hamill
OFREG
Brookmount Buildings
42 Fountain Street
Belfast
BT1 5EE
Northern Ireland
[email protected]
17
2 Market Models – Centralised Vs Decentralised
Market
2.1 Introduction to Market Models
The Regulatory Authorities have agreed to put a single wholesale electricity market in
place. There are two basic high-level structures for electricity markets. These are:
centralised markets and decentralised markets more commonly referred to as gross
pools or net pools respectively. The following section describes both types of
market, gives details of some of the key differences between them and explains why
the Regulatory Authorities have opted for a gross pool design for the SEM.
2.2 Decentralised Market – The Bilateral Contract Market
Model
Market Operation and Participant Activity
A decentralised market, also known as a bilateral contracts market or a net pool, is
characterised by physical bilateral transactions between generators and suppliers.
Participants are incentivised to submit their physical bilateral contracts to the market
operator. These contracts, or schedules, have load and generation that are by
definition balanced, i.e., the load and the generation are equal. Since forecasted
load and generation will not actually balance in real time, participants are required to
reconcile their imbalances after real time using some form of market balancing
mechanism.
Transparency
The contract prices, i.e. the prices at which trades are carried out, for the bilateral
contracts between generators and suppliers are not submitted to the market
operator. Consequently, only parties involved in the contracts have any knowledge
of the contract prices. The only visible prices in the market are those paid through
the balancing mechanism. The balancing mechanism through which only a small
part of the overall market transactions take place is likely to be operated at the
margin. It is entirely possible that the balancing market prices will be unreflective of
actual contract prices and of overall underlying supply/demand fundamentals.
Risk Management
It is common in energy markets for participants to sign contracts of a year’s duration
or more. These contracts are likely to represent the majority of volume in a
decentralised market. Short term contracts may be used to manage real time
deviations from balanced schedules and prevent participants from having to use the
balancing mechanism. Market participants face market risk only to the extent that
their submitted schedule is not fully hedged with an off-take contract.
Price formation and liquidity
The balancing mechanism may consist of either a power exchange or a net pool, that
is, imbalance energy only, and will reflect only a small section of the overall energy
trades in the market. The prices from this mechanism reflect the supply and demand
conditions in the balancing market and not conditions in the overall market. In other
words, the scale of the imbalance market can be a very small part of the overall
market leading to illiquid balancing markets and prices that may not accurately reflect
the overall wholesale price. Furthermore, suppliers in a decentralised market are
18
incentivised to adjust their usage to the extent that their load does not match what
they have contracted to buy from generators. This does not encourage a responsive
demand market.
Dispatch efficiency
Since generators nominate the extent that they wish to run, when aggregated
balancing schedules do not represent real time demand, generators will need to be
moved from their nominated positions. Generators are moved from these positions
based on nominations representing an amount of revenue that they are willing to
receive or forego for generating more or less electricity, i.e., the use of incremental
and decremental offers to the TSO for dispatch or curtailment. The market will tend
towards an efficient dispatch to the extent that the nominated amounts represent the
generators’ short run marginal costs.
Market Structure
Adequate liquidity in a bilateral contracts market is required for a decentralised
market to achieve an efficient outcome. Markets with a significant number of
independent generators and supply companies are generally more liquid than
markets with high proportions of vertically integrated participants. This is because
vertically integrated participants have an incentive to submit balancing schedules that
reflect the natural financial hedge between their business entities. By doing so they
reduce their potential exposure to the balancing market. This issue may become
more pronounced in a market where there are few participants, particularly if one of
these participants has a significant share of both the supply and generation markets.
New entrants
A new entrant generator will typically require an off-take contract with a supplier of
medium to long-term duration. Conversely, a supplier may prefer a contract of
shorter duration since there is a high risk that customer numbers may fluctuate over
that period. New suppliers may have difficulty in procuring contracts that accurately
represent the aggregate demand of their portfolio of customers, which is likely to
fluctuate to a greater degree than existing suppliers. As the customer base changes,
a supply company will be increasingly exposed to the balancing market. Many
potential new entrants to the supply market will find this level of financial risk
unacceptable. Bilateral markets have tended to encourage vertically integrated
structures, and if they do not set out in that manner, market forces have tended to reintegrate to that model. This may also be true of gross pools. However, the
commercial pressure towards vertical integration is not as absolute, more particularly
where different hedge contract off-takers are available.
Renewables
Intermittent generation technology such as certain renewable generators may be at a
disadvantage in a decentralised market because of the strong incentives given to
participants to submit balanced schedules. Suppliers seeking bilateral contracts may
consider intermittent generation unfavourable because of its unpredictable nature.
Large suppliers may use this to gain an unfair advantage, buying energy at an
artificially low price and balancing the schedules across a large portfolio of
generation and demand.
19
2.3 Centralised Market - The Gross Mandatory Pool Model
Market structure
A mandatory centralised market, or gross pool, is one where all electricity is bought
from and sold through a single pool, administered by a market operator. There are
no opportunities for bilateral physical power transactions outside the pool.
Participant activity
Generators submit offers to the market operator, if they wish to sell energy through
the pool. Generators’ offers may have a number of elements, including price/quantity
pairs. Dispatch instructions are issued to generators depending on the offers that
they submit to the market operator. The market operator determines a price awarded
by the pool for energy purchased from generators (pool purchase price) and a price
for all energy that is bought by suppliers from the pool (pool selling price). The pool
purchase price is equal to the spot market or system marginal price, plus an element
designed to provide an incentive for generating capacity to be made available, if
applicable. The pool selling price is the sum of the pool purchase price and any
uplifts paid to generators e.g., start-up or shut-down costs may be paid. It is common
for centralised markets to have some adjustments or uplifts resulting in a pool selling
price that is slightly higher than the pool purchase price.
Transparency
All generators are paid the system marginal price for the energy that they generate
and this price is visible to all generators. In addition, where constraint payments are
made such payments may also be published. Similarly the pool selling price is
published, so all prices are visible to the participants. Participants that wish to hedge
the risk of operating in the market use these published prices to inform their
decisions.
Risk management
In a centralised market all suppliers incur costs at the pool selling price, which may
be volatile and present a financial risk. To mitigate the risk posed by potentially
volatile prices, participants may enter into financial contracts, known as contracts for
differences (CfDs) or hedge contracts outside of the spot market. CfDs are generally
based on the expected value of the pool purchase or pool selling price. In
centralised markets, however, it is common for some load and some generation to
remain un-contracted.
Price formation and liquidity
The market operator determines the system marginal price based on the intersection
of the supply and demand curves. A new price is formed in the spot market in every
trading period. Consequently the price in the spot market is reflective of the overall
supply and demand balance. In a centralised market there is a high level of liquidity
as generating participants seek to maximise revenue by adjusting their offers and
contract positions to reflect the system marginal price. Suppliers contribute to the
market’s liquidity by having CfDs that reflect their expectation of pool prices and
encouraging the reduction of consumption by final customers during times of known
or projected high system marginal prices.
Dispatch
The dispatch schedule is a function of offers submitted to the market operator. The
structure of a centralised market gives generators incentives to offer in a manner that
will ensure that they are run when the system marginal price is greater than or equal
20
to their short run marginal cost. They are then dispatched in a manner that seeks to
meet demand at the lowest overall cost to the system. This operation results in a
dispatch schedule that is closely aligned with system marginal costs.
New entrants
Centralised markets are generally considered to be more favourable to attracting
merchant generation than decentralised markets. Merchant generators do not seek
long term off take contracts to participate in the market. New plants are likely to have
lower marginal costs than older, less efficient plants and they will be dispatched more
often than the older plants if their offers reflect their lower marginal costs.
A
centralised market also provides better incentives to the entry of supply companies
than decentralised markets. New supply companies are required only to purchase
volumes of energy from the pool to the extent that their customers consume energy
although it is likely that such companies will wish to have some financial hedge
contracts in place.
Renewable generators
The centralised market approach generally favours renewable generators. The gross
pool allows generators to submit bids at their marginal cost ensuring that they are
usually called upon to generate, as the majority of such generation normally has
relatively low short run marginal cost. If the pool purchase price is set as the
marginal cost of generation, then the intermittent generator receives this price for the
volume of energy that it generates. Intermittent generators do not require bilateral
contracts to trade in a centralised market. Intermittent generators however may very
well decide to hedge against the pool price, particularly where the pool price may be
volatile given the fixed nature of their costs which ideally would be serviced by fixed
revenue streams.
2.4 Preferred Market Structure
In examining the issues surrounding bilateral markets, the existing Northern Ireland
and Irish markets have proved informative. Each is such that price discovery and
transparency is poor, and it has been evident that investors perceive there to be an
additional risk to enter the market. It is also noteworthy that major investments have
been made by parties, which are vertically integrated, and are in possession of
natural internal hedges.
The Regulatory Authorities are minded to introduce a gross mandatory pool in light of
the benefits this offers over a bilateral market as outlined above. It presents a
number of advantages in terms of liquidity, transparency, dispatch efficiency, its
suitability for a market as small as the SEM, the added incentives for new investment
and fostering renewables and CHP. A detailed analysis of this evaluation is included
in Chapter 6 of this paper. A secondary factor that has been considered is the
implementation and administration of the SEM. The Regulatory Authorities are of the
view that, given the present structure of the industry, a gross mandatory pool will be
easier to implement and administer from participants perspectives and from a
regulatory perspective.
21
3
Capacity Payments
3.1 Introduction
The Regulatory Authorities believe it is imperative that the SEM should incentivise
the required capacity margin and an efficient plant mix. Appropriate signals given to
existing and potential new-entrant generators should ensure an acceptable level of
security of supply. Generators operating in a wholesale market expect to cover their
variable costs in the market and receive some contribution to their fixed costs. The
expectation that the contribution to their fixed costs will provide an appropriate return
on capital employed will largely determine whether an investor will enter the market.
Equally, the failure to secure adequate revenues to cover fixed costs will influence a
generator’s decision to exit the market.
In a gross pool market, most generators will be incentivised to submit offers that are
equal to their short run marginal costs (SRMC), they will thus receive a contribution
towards their fixed costs if their offers are lower than the system marginal price, i.e.
an implicit capacity payment. Generators with short-run marginal costs (peaking
generators) that are often greater than or equal to the system marginal price may not
receive a contribution towards their fixed costs. In this case, peaking generators may
wish to submit offers that are much greater than their short run marginal costs at
times of system stress, in order to receive a greater contribution towards their fixed
costs. A peaking generator may use it’s position to drive the system marginal price
to the level of the market price cap, if one exists. For this approach to function
effectively and to give adequate returns to operators the market will be required to
produce high energy prices at certain times.
There is an alternative approach whereby generators receive a payment through
some explicit Capacity Payment Mechanism (CPM). The CPM thus reduces the need
for peaking generators to submit offers greater than SRMC at times of system stress.
There may be a lower price cap in place than under an implicit capacity payment to
reflect this. This approach is known as the explicit capacity payment, even though
generators with short run marginal costs below the system price will still receive
some contribution towards their fixed costs from the system marginal price.
Intuitively, this market should not require prices to reach the same high levels to
incentivise an appropriate level of capacity.
Economic opinion is divided as to whether electricity markets should contain an
implicit or explicit capacity mechanism. Though there are a number of varieties of
CPM, it is fair to say that each one represents some form of regulatory intervention in
the market. Examples of implicit and explicit capacity payments exist in markets
around the world; their choice and design being influenced by the mix of political,
regulatory and economic characteristics relevant to that market. Certainly, academic
literature on the subject is not conclusive on the most appropriate method of
rewarding capacity in a gross mandatory pool.
In January 2005 the Regulatory Authorities signalled to an audience of potential allisland market participants that the decision on capacity payments was open. The
Regulatory Authorities had arrived at this position having considered a range of
options for CPM (implicit and explicit) and an examination of the pros and cons of
each. Subsequently bilateral meetings were held with interested parties to explore
further the issue pertaining to CPM and generation adequacy.
22
3.2 Implicit CPM
Efficient Decisions
Prices in a gross pool market with an implicit capacity payment can reflect both long
and short term signals about the supply demand balance. A properly functioning
market will interpret the pattern of these signals (regularity, timing, scale) and
respond in an appropriate manner. This will include decisions on the type and size of
plant. By contrast, an explicit capacity payment will dampen the signals sent by the
market and will influence certain aspects of generation investment, possibly the
regularity, timing or scale. The dampening of the market signals may allow the
appropriate generation to be built but there is an associated risk that decisions in this
type of market will be less than optimal.
Market Prices
By the very fact that prices are allowed to fluctuate, based on the supply demand
balance it follows that prices in the gross pool must be allowed to vary and, most
importantly, rise to the high and potentially sustained levels required to signal the
need for new entry. Experience shows, however, that the risk of intervention in such
markets is high, possibly to overcome some perceived timing lag on new investment
or to limit the impact, political or otherwise, of sustained high prices.
Other
The strength of energy-only price signals extend beyond capital investment to
consumer and participant behaviour, which may develop to be responsive to market
signals leading to more efficient decisions regarding consumption, maintenance and
outages. Furthermore, revenue adequacy as determined in a competitive energyonly market has the potential to lead to a more appropriate balance between
entry/exit, maintenance/overhaul and operational decisions. Finally, an energy only
pool that is allowed to persist implies minimal regulatory intervention.
3.3 Explicit CPM
Investment Risk
Explicit CPMs can provide a greater level of certainty over revenue and risk
management than implicit CPMs. For generators the CPM can provide a predictable
revenue stream, or cash flow, albeit payments may be profiled. This translates into
lower risk and cost of capital. It follows that this should encourage investment in the
generation market. In addition a lower cost of capital may ultimately lead to lower
costs for final customers.
Hedging Risk
In a market with an explicit CPM, peaking generators may no longer be required to
set the system marginal prices at the potentially volatile levels associated with an
energy only market. A lower level of price volatility will lower the premium charged to
suppliers for hedging this associated risk.
Targeted Decisions
The fact that a market with an explicit CPM requires central decisions can be viewed
positively. Certain explicit CPMs provide the Regulators with a tool, which can be
used to target decision-making around both the timing of investment and the type of
23
plant. Ultimately a CPM can be designed so as to provide a high degree of
confidence that new generating capacity will enter the market in an appropriate
manner, thus contributing to security of supply.
3.4 Conclusion on Preferred CPM
On balance the Regulatory Authorities have concluded that an explicit CPM should
be introduced as part of the SEM. This decision is driven by the need to attract
timely investment, retain capacity and encourage efficient exit recognising specific
characteristics of the all island market. Particularly, the scale of the market, the
relative size of new investments and their impact on market dynamics and
consequent uncertainty.
In arriving at the decision in principle to adopt an explicit CPM in the SEM the
Regulatory Authorities have been mindful of the particular characteristics of the all
island market including market scale, and the recent need for regulatory interventions
in relation to generation adequacy.
There are valid arguments on both sides of the CPM debate. On balance, and in the
context of the all island market, the decision to adopt an explicit CPM is based on:
• Prices – The prospect of more stable pricing in the market.
• Market Entry & Risk – The expectation that stable and predictable cash flows
will reduce the risk premia for new investments and thus facilitate market
entry.
• Intervention – The acknowledgement that an energy only pool is more likely
to carry a risk of regulatory or political intervention and the follow-on effects
on investment arising from this uncertainty.
• Transparency – Properly designed, an explicit CPM can lead to greater
transparency as to the basis of the energy pool prices, over and above the
transparent basis for the CPM payments themselves.
• Competition – A market that reduces risk and barriers to entry is seen as
providing the essential ingredients. Properly designed, an explicit CPM can
maintain appropriate signals in relation to availability and investment timing.
• Dominance – It can also be helpful in dealing with dominance in the
generation market.
3.5 Criteria for Selection or Design of an Explicit CPM
Given the proposal to adopt an explicit CPM in the new market, it is necessary to
design a mechanism that delivers the benefits identified and avoids the potential
downsides to the maximum extent possible. The Regulatory Authorities have
concluded that any explicit CPM should be required to satisfy the following range of
criteria in a balanced manner;
• Incentivise appropriate levels of market entry and exit.
• Encourage efficient mix of plant types.
• Does not “double pay” generators.
• Reduce risk premium for investors.
• Is compatible with energy market.
• Encourage short-term availability when required.
• Encourage efficient maintenance scheduling.
24
•
•
•
•
Does not increase costs to consumers for desired security margin.
Reduce market uncertainty.
Not unfairly discriminate between participants.
Transparent, predictable and simple to administrate.
3.6 Issues for Consultation
In arriving at its proposal to adopt an explicit CPM, the Regulatory Authorities have
identified a number of issues which will need to be addressed before a design for the
explicit CPM can be finalised and on which industry comment is specifically
requested at this stage.
Value of Capacity
In designing any CPM a key question will be the value placed on capacity. For
example, should the value of capacity reflected in the CPM be that of a Best New
Entrant or a new peaking plant? The Regulatory Authorities are mindful that this
decision will influence the type of investment. The value of capacity should not
impact on the ability to design a CPM, which does not completely dampen the market
incentives for generators to act competitively. Allied to the question of value is also
the question of flexibility and the degree to which the mechanism should change with
time to reflect changing requirements on plant type/mix.
Eligibility
There is a question as to whether all generation units should be eligible to receive
explicit capacity payments. Should explicit capacity payments be made to units that
are available to run, units that are running or dispatchable units?
Renewable/CHP Treatment
Reflecting the balance of arguments on both sides of the issue, market participants
have identified preferences for implicit and explicit capacity payments. Much of this
is derived from the viewpoint of large thermal units, which can to a greater or lesser
degree be controlled to respond to short run market signals. The Regulatory
Authorities are mindful that the situation for CHP and wind units differs in that they
may either be “must run” or “will run”
Treatment of Interconnectors (Moyle)
The question of how interconnectors will be treated under an explicit CPM is
important. Will interconnectors be entitled to capacity payments? If so, how would
such arrangements interact with existing arrangements for the procurement of
interconnector capacity?
Demand Participation
The Regulatory Authorities view demand side participation as an important
contribution to both competition in the all island energy market and as a potential
contributor to security of supply. To this end, the question arises as to how demand
side participation might work in the context of an energy pool with explicit capacity
payments. What reasonable obligations can or should be placed on demand side
participants and, flowing from this, to what extent should they attract capacity
payments?
25
Price Cap Options
One of the benefits of an explicit CPM is that pool prices are expected to be
considerably less volatile and may be easier to forecast. The risk of intervention is
reduced to the extent that any price caps are set appropriately, though price caps
ipso facto represent a degree of regulation for all generators. If price caps are not
mandatory, and prices are allowed to achieve any level in the market, some form of
one-way market hedge might apply whereby revenues in excess of the hedge cap
are recycled to suppliers and in turn consumers. In both cases, how should the level
of the cap be determined? In either case any cap(s) should be mindful of price caps
in interconnected markets. Energy may be exported from the area with lower price
caps at times when it is most needed.
Conclusion
The Regulatory Authorities invite interested parties to comment on the issues raised
in this section. Comments on the following questions would be particularly welcome:
•
How should the value of a capacity payment be determined and why?
•
What generation units should be eligible for explicit capacity payments and
why?
•
Should capacity payments be made to intermittent sources of energy e.g.
wind turbines? If no why not, and if yes, what capacity could be attributed to
such sources?
•
Should plants that are “must run”, such as CHP units receive capacity
payments?
•
Should interconnectors/interconnector participants receive capacity
payments?
•
Should demand side participants be paid a capacity payment? If so, what
would the value of the capacity payment be and what reasonable obligations
could be placed on demand side participants in this instance?
•
Should there be a price cap in the SEM, if so what would be an appropriate
methodology to determine a price cap?
26
4 Common Design Themes for the Gross Mandatory
Pool
Having considered the issue of explicit capacity payments, the next two sections of
this paper address the key high level design features and options for a gross
mandatory pool. This section addresses design themes that will apply to any gross
mandatory pool design adopted while section 5 looks at two variants of the gross
mandatory pool design.
A gross mandatory pool may take any of a number forms. Features such as the
dispatch mechanism or the pricing mechanism define each individual market.
Though in theory this can give rise to a large number of market types, in practice it is
important that the features of a market are internally consistent and do not result in a
market that is difficult to implement or difficult to operate leading to internal
inconsistency. The Regulatory Authorities have presented two market models
described below, which are believed to be internally consistent.
4.1 Unconstrained Market Clearing Price
For reasons of simplicity and transparency, it has been decided that the SEM shall
adopt a single unconstrained marginal pricing structure, i.e. the price determined
within the market will ignore transmission constraints but will respect generator
physical abilities, where the marginal unit sets the market price for the entire market
based on an optimised dispatch over 24 hours. The price and quantity offers of all
generators within the SEM will be sorted in the unconstrained schedule into
ascending merit order on the basis of the price element(s) of their offers taking
account of start-up and other costs. No account will be taken of transmission
constraints to derive this price curve. The price in each trading period will be set by
the marginal unit subject to uplift for start-up, rundown costs etc. These units shall
be referred to as plants in the merit order for the remainder of the document.
The demand curve is the sum of all demand in each trading period. This approach is
considered to be the simplest way to calculate a market price. As such it is relatively
easy for participants to forecast and to incorporate into risk management strategies.
By definition, all electricity is bought and sold in this market. Therefore the spot price
in each trading period represents a liquid market. This typically means that prices
will be high when demand is high and vice versa. Financial contracts, e.g., contracts
for differences, are likely to influence and be influenced by spot market prices.
The exact details of price determination will be developed during the detailed rule
development stage.
4.2 Compensation for adjustments
There is a limit to the amount of power that can physically flow through transmission
lines. As a result, it is not possible to schedule all combinations of generation to
meet every load on the system. This leads to generators being constrained on or off
the system.
Generators that are not in merit order, i.e., generators whose offers were at prices
that were higher than the market-clearing price, may be requested to run or partially
27
run for system stability reasons. Usually, such generation is called upon to provide
reserves and this is discussed further later. Similarly, some generation units whose
offer prices were lower than the market-clearing price may not be able to be
dispatched for similar reasons. A generation unit that is prevented from exporting
energy due to the physical limitations of the transmission network or that faces a
reduction in exported energy is said to be constrained off. One that is out of merit but
dispatched to resolve a transmission constraint or is required to provide reserves is
said to be constrained on. The term constrained on/off also refers to plant that are
partially constrained up/down.
This in turn raises the question of payments, in addition to the market clearing price,
to those who are dispatched when the market clearing price is below their offer price
(constrained on payments), and compensation for those who offered less than the
market price and were not dispatched (constrained off payments), as well as the
issue of who funds these additional payments.
Constrained-on Payments
The case for constrained on payments is clear: there is no intention to force
generators to generate and be paid less than their offers. A constrained-on plant will
get paid its offer price for the appropriate portion of the plant that is constrained on.
The appropriate price for each portion of the curve constrained on will be used
because offers are likely to be in tranches or curves rather than a single fixed point.
If a generator provides an offer curve it is possible to be partially in the merit order
and partially constrained on. The offer price of the constrained on plant shall be the
offer price that applies to the constrained on portion only, the in-merit dispatched
portion will receive the simple stack price.
Constrained-off Payments
The case for constrained off payments is less clear. The argument for constrained
off payments is largely related to the concept of firm financial transmission access
rights: if the generator is in the merit order, it is deemed to have a firm right to
generate and transmit. If it is denied that right, then it should be compensated for the
loss of opportunity. Constrained off payments might then be based upon the
difference between the unconstrained single market-clearing price and the
appropriate generator offer, where the generator offer shall not be lower than the
avoidable cost of the generator, which may be defined from time to time by the
Regulatory Authorities.
The Regulatory Authorities are minded to include
constrained-off payments in the SEM. However, further consultation is required to
address intermittent generation, CHP and pumped storage and the rules for any
payment to such generation.
Regulation of Constraint Payments
Constraint payments are susceptible to gaming. If a generator knows that it will be
constrained on, it can increase its offer above competitive levels to maximise profit.
Conversely a plant that is often constrained off may reduce its offer prices, knowing
that if it is in merit and dispatched it will receive the single market-clearing market
price; if it is constrained off it will receive the difference between its offer and the
market price.
28
In the longer term such gaming may bring new investment in locations where it is not
required. Often there is a case to limit the constraint payments for plant that are
regularly constrained either on or off. A set of regulatory rules will be developed as
part of the detailed design of the SEM to mitigate gaming of constrained on/off
payments.
Constraint Payments for Non- Thermal Plant or Non Conventional Thermal
Plant
When considering constraints above, the discussion is focused on conventional
constraints arising from network shortcomings or the need to provide operating
reserves. It should be noted that such an approach to constrained off payments may
not be appropriate in all circumstance e.g. where constraints arise from features
unique to the particular generators, such as unpredictability, inherent variability or
other plant characteristics.
Such payments also raise questions as to the appropriate approach to be taken to
traded environmental certificates. Further consideration will have to be given to
these issues during the detailed market rules development.
4.3 Interconnector Trading
Arrangements for trading power across interconnectors are often complicated,
especially if the interconnector joins markets of different types, e.g., a centralised and
decentralised pool, or markets with significantly different timetables with respect to
gate closure and dispatch.
Much of this complication disappears if the interconnectors are absorbed into a wider
single market, such as the SEM. When incorporated into a single market, those who
wish to transfer energy across the interconnector simply offer generation. When the
market is cleared, the trades across the interconnector are simply a part of the
generation dispatch. In other words, generation units are dispatched solely
according to the offers received and the constraints imposed by the transmission
system, including those imposed by the interconnector. It is proposed that the SEM
shall treat the North-South interconnector as an embedded component of the
transmission system.
It is envisaged that the SEM will trade with other electricity markets, such as BETTA.
A detailed set of rules for such transactions will be required but are not considered as
part of this paper.
4.4 Locational Signals in the SEM
A single unconstrained marginal pricing structure means that the SEM will contain no
locational pricing signals by comparison with, for example, a locational marginal
pricing market. The locational value of generation or demand is therefore not
signalled within the market price. But this does not mean that there will be no
locational signals in the SEM as locational signals will be given through:
•
•
•
the treatment of losses
use of system charges, and
constrained on and off payments.
29
The reasons for adopting a single market price have been set out in section 4.1. The
Regulatory Authorities consider that these benefits outweigh the locational signal that
would arise from zonal or locational pricing and that the treatment of losses, use of
system charges and constraint payments will provide adequate locational signals in
the SEM.
4.5 Losses
Losses associated with the transmission of electricity in the SEM will need to be
accounted for. There are a number of elements to this issue. The first concerns the
task of ensuring that there is sufficient generation scheduled to cover the actual
demand as well as the associated losses. The second is the question of how the
cost of losses is recovered; thirdly should losses provide a locational signal or be
socialised and finally whether losses should be static or dynamic.
In a market that is operated under a modern constrained dispatch process, the
impact of losses in terms of the scheduling of sufficient generation is an implicit part
of the market clearing process. That is, the impact of losses is taken into account by
the system operator in each dispatch. Thus the first issue does not present any
serious problems.
The second issue is more problematic. The easiest option is simply to smear the
cost through a price uplift across the market or by applying an adjustment to the
quantities of electricity produced by each generator. Applying a price uplift or
quantity adjustment should result in the same total revenue to each generator. At
present a quantity adjustment is used in both jurisdictions and the Regulatory
Authorities propose to continue with this approach as a price uplift introduces
somewhat greater complexity particularly in managing hedge contracts.
With respect to locational signals, the lack of any locational signals provides no
incentive for generation (or load) to take into account the cost of losses when making
decisions with respect to their location in the market. Basing loss factors on marginal
losses will correctly value the marginal cost of electricity to loads and generators and
thus theoretically ensures a more efficient supply/demand balance. At present, loss
factors in the south are calculated based on marginal loss factors whereas in the
north, average loss factors are applied. It is proposed to adopt marginal loss factors
in the SEM in order to provide some locational signals to the market. It should be
noted that this decision is not taken in isolation. Policy on loss factors has a very
strong link to connection policy. The Regulatory Authorities have also considered
connection policy and have concluded that a shallow connection policy for generator
will be adopted in conjunction with SEM.
The question of how to calculate the loss factor then arises. Should losses be
calculated dynamically (i.e. every trading period) or alternatively, should losses be
calculated using static loss factors that are calculated on an annual basis and applied
to the volumes produced by each generator? It is proposed that static rather than
dynamic loss factors are used in the SEM initially as is the present practice in both
jurisdictions for reasons of simplicity and ease of implementation.
30
4.6 Dispatch and trading periods
The dispatch and trading periods refer to the units of time used for the purposes of
respectively determining the dispatch of the power system and the financial
transactions.
The dispatch period is the period for which the dispatch instructions apply. It is
usual that the dispatch instruction represents a target to be achieved at some point
during the dispatch period. In most instances this is the end of the dispatch period.
The trading period is the time period for which a particular price or prices apply.
Pricing and dispatch are separate, though related, processes. Prices and dispatch
can be calculated at different times because they are separate. There are some
minor disadvantages associated with this approach. Dispatch decisions will be
based upon generator offers and prices determined by them. Participant offers used
for either process have the same source. It is likely that a common offer database
will receive and validate all participant offers and provide the offer data for dispatch
and pricing calculations. Calculating pricing and dispatch at different times would
create the possibility that different offers from the same participant could be used for
each calculation. If the same set of offers is not used for pricing and dispatch a
significant opportunity to game pricing and dispatch calculations is created.
The length of the two periods is a compromise between the precision of a short
period and the reduced costs of operating and settling a less frequent market.
Shorter periods mean that calculations of quantity and price are more likely to
accurately reflect the supply-demand balance. Thus, shorter periods reduce the
need for measures to compensate for deviations from the dispatch quantity and price
within the period. The accuracy of dispatch is also related to how long before a
particular period the calculations are made.
The current trading period in both Northern Ireland and Ireland is 30 minutes
(although Ireland has the facility to have 15 minute intervals), with metering and
settlement systems in both jurisdictions configured to reflect this. A shorter dispatch
period of 5 minutes may be appropriate because it would reduce reserve
requirements needed to deal with deviations. However a 5-minute trading period
would require significant investment in metering and settlement systems, for this
reason the Regulatory Authorities consider that it is inappropriate.
Therefore to encourage efficient pricing that most appropriately reflects the
supply/demand balance, the trading period shall be 30 minutes. The Regulatory
Authorities consider that a 30 minute dispatch period is also appropriate. However it
recognises the practice by system operators of issuing dispatch instructions more
frequently. The exact details of how intra-dispatch period instructions will be dealt
with are to be determined within the detailed market rules.
4.7 Ancillary services
The SEM will require a number of ancillary services for its efficient and reliable
operation. Services required include various classes of operating reserve and
voltage control. Typically these classes of operating reserve include a load following
service, spinning reserve to respond to sudden drops in frequency, fast start reserve
to react quickly when the capacity margin is dangerously low and black start reserve
to restart other generation units in the event of a total system blackout. Currently
31
reserve class definitions are different in both Ireland and Northern Ireland. It is
proposed that a consistent reserve definition is developed and applied in an all-island
context.
The key issues that need to be resolved in relation to operating reserve are
procurement, pricing and deployment. It is proposed that a single body will procure
operating reserves by competitive contract in the SEM. These contracts will reflect
the fee that a generator wishes to receive for providing reserve over and above the
opportunity cost of not running. The TSO will deploy operating reserves in a manner
that seeks to minimise the overall cost to the system with respect to the contract
prices and the marginal cost of energy.
It is proposed that the cost of the reserve requirement in each trading period is
apportioned for on a “causer-pays” basis. The generation unit that causes the largest
single risk of failure will pay the largest portion of the reserve costs. This may be
extended to cover groups of generation, which act as a single contingency.
4.8 Market data
The publication of market data plays an important role in facilitating efficient market
operation and transparency. As a general principle, the more information that is
made available the more likely it is that market participants can make informed
decisions on their willingness to supply or consume energy. Disclosure of
information may also provide part of a check on price manipulation through particular
bidding strategies.
In practice, the release of information must be balanced with considerations of
commercial sensitivity and/or the opportunities that publication may provide for
collusion or market manipulation.
To encourage competition and investment it is anticipated that an open approach to
information disclosure will be adopted. The Regulatory Authorities will examine each
category of data for publication and the associated timescale to ensure that
publishing it will not impose any unnecessary costs on the market. It is the view of
the Regulatory Authorities that the following information should be published within
the stated timescales:
Ex-Ante
−
−
−
Any known binding network constraints;
Forecast system demand and
Pre-dispatch runs.
This data should ideally be available both before gate closure and as soon as
practically possible after gate closure.
Each trading period Ex-Post (As close to dispatch as possible – Unvalidated)
−
−
−
Final energy and reserve offers;
Final energy offers and
Actual availabilities of generating units and dispatchable load.
32
For each trading day
−
−
Scheduled generation, scheduled load and scheduled reserves for each
generating unit, the interconnector (price and quantity) and dispatchable load
and
Summary of system information determined by the SO
Ex Post after a suitable time interval (as soon as possible after the settlement
period)
−
−
Identification of each unit submitting a price schedule and
The dispatch price schedule of each generating unit
4.9 Conclusion
The Regulatory Authorities invite comments on the matters raised in this section. In
particular, views on the following issues would be welcome:
•
How should constrained-on and constrained-off payments be made? Who
should receive such payments be made and under what circumstances?
How should the revenue for such payments be recovered? Suggested
models along with reasons for the preferred approach would be welcome.
•
How should reserve requirements be charged for under the SEM and why?
•
What form of “causer pays” mechanism should be adopted for ancillary
services and why?
•
Is there any additional market data that should be published and why would
the data you suggest be of help to the market?
33
5 SEM Market Model Options
There are a number of key attributes to market design which, when combined in
different arrangements can lead to a multitude of market design options. However,
the Regulatory Authorities have distilled the various design and market options down
to two distinct types. Since both options may be either energy only or could include
an explicit capacity payment, the issue of capacity payments has been dealt with
separately in section 3. The Regulatory Authorities set out two market models
referred to hereafter as the “self commitment model” and the “central commitment
model” hereafter. Both of these models represent viable alternatives which are
thought to be internally consistent. The remainder of the section describes the
features of these two models. The models are subsequently evaluated before
concluding that the Regulatory Authorities are minded to implement the central
commitment model.
5.1 Definitions
Central to the understanding of the differences between the models examined below
is the detail behind participant bids, price formation and the system dispatch options.
A number of definitions are included here to ensure clarity when considering both
models.
Real-time schedule:
The dispatch schedule, with target energy, regulation (governor control) and reserve
levels of output of generation units that is to be physically implemented.
Pre-dispatch schedule
An indicative look-ahead generation schedule which runs from “now” forward to the
end of the look-ahead horizon that is between the end of the following day and seven
days out.
Dispatch
The act of instructing a generation unit as to the level of physical operation required
in a given dispatch period or the act of receiving an instruction as to the level of its
physical operation required in a given dispatch period, or of operating in accordance
with such instruction, as the context may require.
Security Constraint
A generic constraint defined by the system operator, which may reduce the efficiency
of the dispatch schedule for the purpose of maintaining the security of the power
system.
Forced Outage
An unanticipated intentional or automatic removal of equipment or the temporary derating of, restriction of use or reduction in the performance of equipment.
Dispatch Period
The period of time over which a dispatch instruction applies.
Trading Period
The period of time for which a trading price is set and the basis for settlement of the
energy market
34
5.2 Self-commitment model
In the self-commitment model all participants are considered available for dispatch in
a dispatch interval based upon the offers that they make for that dispatch interval.
The generators themselves are responsible for their commitment and signal this
through their offers. No party has all the information relating to every generator.
Information is networked and the efficiency of the commitment relies upon feedback
loops that inform generator offers.
Generator offers
The dispatch schedule of the self-commitment market is determined by the offers
submitted by each generator. In the self-commitment market generators submit
offers that include price-quantity pairs only. The price-quantity pair will consist of a
number of monotonically increasing prices that the generator is willing to accept for
generating different amounts of energy. There will be a record of some limited
technical information relating to each generator and this will be used to ensure that
the bids submitted are technically feasible for each plant.
To the extent that demand side bidding is feasible, demand participants may submit
offers to reduce load. These offers will also consist of a number of price-quantity
pairs that the participant is willing to accept for reducing demand.
Frequency of offers
In a self-commitment market the frequency of offers is a function of the dispatch and
trading period. If prices are calculated on a daily basis, then there is little need for
offers that are more frequent. However, prices in a self commitment market would be
calculated every half-hour and the efficiency of the self commitment market relies
upon an effective feedback loop between generator offers and an indicative dispatch
schedule. Generators will use their offers to ensure that they achieve a feasible
dispatch schedule. The frequency of offers coupled with an indicative pre-dispatch
schedule will provide generators with sufficient feedback to get a feasible operating
schedule.
Gate closure
Gate closure marks the point prior to dispatch when participants can no longer
change their offers to generate or consume electricity. Gate closure needs to allow
sufficient time for the determination of dispatch instructions, and possibly prices, and
for the system operation functions to be carried out where a single price setting and
dispatch algorithm is used. Typically self-commitment markets have short gate
closure times where participants may wish to change their offers right up until gate
closure to achieve their desired dispatch. It was considered that gate closure would
be initially 4 hours moving to one hour prior to dispatch under the self-commitment
model. Elements of an offer may change after gate closure in certain circumstances,
including generator emergencies. These changes would be known as a redeclaration and the criteria for such re-declarations would be defined and published.
Dispatch Schedule
Generation units are dispatched to meet the system demand in each trading period,
respecting transmission constraints and static loss factors at the lowest cost, based
on generator offers. The trading intervals do not take account of one another, apart
from the constraint that movements in generator output from one period to another
cannot exceed certain technical characteristics, e.g., plant ramp rate.
35
Price formation
The pricing in the self-commitment market may be ex-ante. That is, the price would
be set prior to the trading and dispatch period and after gate closure. The ex-ante
price would be based on a projection of system demand during the trading period. In
order to ensure that the ex-ante price accurately reflects real-time operating
conditions it would be set as close as possible to when the dispatch schedule is
issued. It is the view of the Regulatory Authorities that in a self-commitment market,
ex-ante prices will provide certainty to demand participants who may wish to respond
within period and to generators between trading periods.
As stated previously, there is a single price that is set by the marginal unit on an
unconstrained basis. In the context of the self-commitment model this means that in
each trading period, the price and quantity offers of all generators are sorted into an
ascending merit order on the basis of the price elements. The marginal price for the
system (paid to generators) is set at the point where the projected demand curve
intersects with the unconstrained supply curve, known as a simple stack. To
maintain system security it may be necessary for the system operator to dispatch
units that are not in this simple stack and not dispatch units that are in this simple
stack. Where this arises the issue of constrained on and constrained off payments
arises. One of the benefits of using an unconstrained pricing model is it will clearly
identify constraints on the system.
5.3 Central-commitment model
Central commitment results in dispatch schedules which are derived by optimising
the unit production over a long time period, e.g. 24 hours, and where dispatch is
determined by a central body that has both the technical capabilities of each unit and
prices available to it. A key feature of this market is the provision of more offer
information by participants in the form of technical data and prices. This information
is used by the central body determining the dispatch schedule derive a feasible
schedule. This contrasts with a self commitment market as stated earlier, where
participants are required frequently to change their offers to reflect the feasibility of
their offers.
Generator offers
The calculation of an efficient dispatch schedule in a central-commitment market is
dependent on the central operator receiving factual information from generators.
Generators will be required to submit technical parameters such as minimum running
levels, ramp rates and minimum run times as well as economic information such as
start-up/shut-down costs and a number of monotonically increasing price quantity
pairs.
It is expected that generators will submit a single set of price quantity pairs for each
trading day, though they may be required to submit price quantity pairs for each
trading period. Typically, the technical parameters are held on a standing basis and
are only updated when there is a material change in the operating characteristics of
the plant. The technical and economic parameters submitted are expected to
encourage generators to submit bids that more accurately reflect their short run
marginal costs under normal circumstances. A central authority will audit these
parameters form time to time to examine whether parameters are consistent with
actual unit performance.
36
Frequency of offers
Scheduling in the central-commitment market depends on the knowledge of a central
operator and much less on an efficient feedback loop informing generators of their
position in the merit order. As a result, offers will be submitted to the central operator
once a day regardless of whether specific offers are required to relate to an entire
trading day or specific trading periods. To enable demand side bidding an indicative
price will be provided ahead of real-time. An indicative running schedule will also be
provided to generators though this is intended to assist secure generator operations
rather than influence their offers.
Gate closure
Gate closure is required to be suitably long to allow sufficient time for the
determination of dispatch schedules. The dispatch schedule is calculated by a
central authority and since participants are not expected to react dynamically to
market conditions gate closure needs to be long enough to allow an efficient dispatch
schedule to be calculated. It is proposed that gate closure will be 12 hours before
the start of the trading day. The technical characteristics of a generator may change
after gate closure in certain circumstances. It will be mandatory for generators to
inform the central authority of these changes in circumstances. In certain predefined
circumstances participants may be allowed or may even be required to re-declare or
re-offer.
Dispatch Schedule
The dispatch schedule will be calculated to meet the system demand at the lowest
cost optimised over a 24-hour period. This optimisation respects transmission
constraints as well as the technical and economic parameters provided by the
generators.
Price Formation
In the central-commitment market the price will be formed ex-post (i.e., after real-time
for each trading period). This ex-post price has the advantage of accurately
representing the actual system demand during each trading period. It is the view of
the Regulatory Authorities that in a central commitment market an indicative ex-ante
price should provide a suitable signal for demand side participants to respond to.
5.4 Conclusion
The models outlined above are each believed to be internally consistent, and when
taken in conjunction with the detail in Chapter 4, are viable and pragmatic models for
the SEM. The Regulatory Authorities are minded to implement the central
commitment model. The detailed evaluation that supports this choice is addressed in
the next Section.
37
6 Evaluation of Models
6.1 Evaluation Criteria
It is envisaged that the SEM will deliver an efficient level of sustainable prices to all
customers for a supply that is reliable and secure in both the short and long run on
an all-island basis.
Fundamental to achieving this objective will be the creation of an effective and
efficient all-island wholesale electricity market. Although there is no universally
accepted or perfect solution to the various complexities that comprise an electricity
market, there are some well-established principles for good wholesale electricity
market design. An effective wholesale market should:
− facilitate the development and operation of a secure power system to meet the
reasonable demands of customers;
− provide market operations that are predictable, transparent and stable;
− incentivise efficient production and new investment through competition;
− not place undue overhead costs on the industry (and by extension the final
customer);
− determine prices that fairly reflect the costs of production and power system
conditions;
− not unfairly discriminate between participants on grounds other than those of
economic and power system efficiency; and
− allow for active participation of the demand side of the market.
A wholesale market design underpinned by these principles should create a solid
basis for engendering investor confidence. This is founded on the assumption that
market dominance and market power is addressed effectively by the Regulatory
Authorities in a clear transparent and verifiable manner. The Regulatory Authorities
will do this irrespective of the market design selected.
The evaluation criteria employed in assessing market design options are a distillation
of the above fundamental market design principles into a set of attributes. These
attributes were used to assess the quality and fit of each market design option and
they are organised into separate criteria.
Security of Supply
The chosen market design should facilitate the operation of the system in a secure
manner. The market should meet the reasonable demands of final customers.
Stability
It is important for reasons of investor confidence that the trading arrangements
should be stable and predictable throughout the lifetime of the market. Stability may
also refer to the extent that a design should result in prices that are efficient and
sustainable in the longer term.
Efficiency
Efficiency is the extent to which the market design encourages economic dispatch
leading to the appropriate amount of electricity being produced/consumed by the
appropriate producers/consumers. Market design should in so far as it is practical to
do so, the most economic dispatch of available plant.
38
Practicality
The practicality of the market refers to the cost of implementing and participating in
the wholesale market arrangements. This also refers to the extent to which the
market design lends itself to an implementation that is well defined, timely and
reasonably priced.
Equity
This criterion refers to the degree that the market design allocates the costs and
benefits associated with the production, transportation and consumption of electricity
in a fair and reasonable manner.
Competition
Competition refers to the extent to which the trading arrangements incentivise
appropriate investment and operation within the market and more specifically the
extent to which the market does not provide barriers to entry or exit. A key
determinant of this conduciveness to competition is an assessment of the extent to
which the market outcomes and allocation of the costs and benefits associated with
the production, transportation and consumption of electricity is clear and can be seen
objectively. From a participants perspective it relates to seeking dispatch at the most
opportune time and to the optimal capacity in order to maximise profits.
Environmental
It cannot be assumed that every market design will facilitate renewable generation.
Though the Regulatory Authorities accept that a market cannot be designed
specifically around renewable generation, any trading arrangements introduced
should have due regard to generation from renewable sources. This criterion refers
to whether or not the selected all-island wholesale market design model is conducive
to renewable energy generation involvement. It also refers to whether or not the
design supports CHP and demand side participation.
Adaptive
It is also important that the trading arrangements implemented allow for slight
changes to be made in order for the market to develop. For these reasons the
evaluation framework includes this further criterion. This criterion refers to whether
or not a market design provides an appropriate basis for the development and
modification of the arrangements in a straightforward and cost effective manner.
6.2 Evaluation of Markets – Centralised –v- Decentralised
This section sets out the evaluation of the preferred high level design of the SEM.
The evaluation is divided into two parts; firstly, we have considered the question of
centralised versus decentralised markets and concluded that a centralised market in
the form of a gross mandatory pool is the preferred market model to adopt. Secondly
we have evaluated the central commitment and the self commitment market models
and concluded that a central commitment market model is preferable. In considering
the central commitment model price setting and related issues were also considered.
The design at its highest level consists of a choice between a decentralised market
and a centralised market. The differences between these markets were discussed in
detail earlier.
These markets were analysed through the evaluation framework and the results are
summaries in the following table.
39
Decentralised
Market
Centralised
Market
Security
of
Supply
Stability
Med
High/Med
Med/Low
High
High/Med
High
Efficiency Practicality
Equity
Competitive
High
Low
Low
High
High/Med
High
Security of Supply
Security of supply can be addressed under two time-frames; the short-term where
adequate volumes of the existing portfolio of generation plant is made available to
meet demand at any given time, and the long-term where adequate generation
capacity is assured on a year-to-year basis.
In the short-term the decentralised market requires sufficient plant to be available at
any given time to meet demand. The decentralised market allows generators to
nominate the amount that they wish to generate and recent practice shows a trend
towards over-nomination, which bodes well for security of supply purposes. Where
the nominations lead to under-nominations the system operator changes the dispatch
instructions to maintain system stability based on constrained-on bid prices. Overall
a decentralised market is ranked highly in relation to short term security of supply.
The centralised market generally requires the system to be dispatched in a manner
that is reflective of the underlying supply/demand balance. The system operator still
dispatches in a manner that reflects system security certainty. This market model
seeks to balance the issue of security of supply with economic efficiency in the shortterm. In a market that has a low level of liquidity a centralised market provides
greater price transparency and greater assurance of economic dispatch. Therefore
the centralised market is also ranked highly in relation to short term security.
In the longer-term, lack of price transparency such as that arising in a net pool
market can pose a problem for new entrants and act as a barrier to entry. In
addition, a small pool of balancing energy similarly may pose problems for new
entrants as it may provide very volatile balancing prices which increases risk. A
centralised market offers new entrants a better opportunity to buy and sell their
energy at transparent market prices and should facilitate new entrants. In addition,
price transparency makes it easier to evaluate investment opportunities, whereas
lack of price disclosure in the market makes investment more problematic. Overall
therefore, the centralised market is considered to rank more highly than the
decentralised market in relation to signals to encourage entry so as to meet long term
security of supply requirements.
Stability
In a decentralised market the contracted prices between suppliers and generators
are generally negotiated in medium to long-term horizon based on physical trades.
Participants are still exposed to spot prices in a decentralised market, but only for
energy that is required from others or where it is sold to others, (i.e. under the
balancing mechanism). For larger market participants, less energy may be bought
under the balancing mechanism provided that such participants have access to a
portfolio of generating units, whereas smaller players are often faced with
proportionally greater volumes of energy purchased at market balancing prices. This
40
represents a greater risk to small players in the market who have less control over
balancing prices and where they may be fully exposed to balancing prices.
In some markets trading in balancing energy is sufficiently liquid that forward trades
are made to provide some mitigation in balancing risks. This raises the question of
market liquidity, which is presently low in the all-island context and is unlikely to
deliver stable prices in a balancing market. Where liquidity is low at present greater
vigilance is required on the part of the regulator to ensure balancing prices are not
unduly manipulated. This presents a greater challenge for Regulatory Authorities
due to the lack of price transparency in a decentralised market.
The centralised market requires all generating participants to sell to a pool and all
demand participants are required to purchase from the pool. The price in this pool,
were it to be energy only, would fluctuate significantly between trading periods. It
has been suggested that the price would have to attain the level of Value of Lost
Load (VOLL) for at least up to eight hours each year to provide sufficient revenue for
participants. Further, an energy only market depends on fluctuating prices and in
particular, it relies on peaking plant or in some cases mid merit plant exercising
market power when it knows it is the last plant called upon to produce energy,
thereby setting the market price at the market ceiling.
It is likely that both centralised and decentralised markets will result in significant
price variability, which in itself is required for proper functioning of the market and as
long as market participants can predict and model such variability. However, it is
more difficult to predict price variability in a decentralised market due to lack of
transparency.
This leaves a risk within a centralised market that the price may not reach the ceiling
often enough to provide revenue adequacy, which could result in unpredictable price
formation. In addition centralised markets are likely to exhibit prices which are more
variable than that of a decentralised market.
Overall therefore the centralised and decentralised markets are ranked at a similar
level in relation to stability (high to medium). However this is for different reasons as
outlined above. In addition, there are a number of design features that may dampen
the price fluctuations and make price variability more predictable such as capacity
payments. This is addressed earlier in the paper and could be applied to either
model – the centralised or decentralised – brining more stability to the market in the
medium to long-term.
Efficiency
Efficiency in terms of delivering an economic dispatch and efficient dispatch (i.e.,
efficient operation and administration of the market) can be delivered by either a
decentralised or centralised market. Industry structure at any given time may play a
significant part in delivering economic dispatch. Therefore, the issue of choosing
between centralised or decentralised markets must also take into account the
structure of the industry, which is highly concentrated at present.
It is the view of the Regulatory Authorities that the present industry structure on the
island lends itself to choosing a centralised market in order to deliver economic
dispatch. This is because the centralised market is likely to offer generators a strong
incentive to bid at their marginal cost. In addition a centralised market will offer a
greater degree of transparency which is important in the context of the present
industry structure. A decentralised market on the other hand, with the lack of
41
transparency in pricing and the fact that there is significant industry concentration,
may not lead to the most efficient dispatch.
In addition, with respect to efficient dispatch, the Regulatory Authorities are of the
view that a centralised market will be less costly to implement and operate when
weighted in conjunction with the benefits of a gross mandatory pool. Therefore the
centralised market is ranked more highly than the decentralised market on this
evaluation criterion.
Practicality
The decentralised market represents less change from the current market
arrangements than the centralised market does, though neither market option could
be considered as trivial in terms of change implementation. The cost of participating
in either type of market may depend on the frequency at which generating schedules
or offers are submitted, though this may be less frequent in a decentralised market.
Therefore both markets present practical challenges. However, greater challenges
will reside in the details of the market than at a high level. Therefore both are ranked
on an equal basis from a practical perspective.
Equity
For a market to be equitable it should present the same set of challenges to all
participants. In reality the market model on its own is unlikely to be the only factor in
determining equity. The characteristics of the participant will also have a significant
bearing. However to the degree that the market model has some bearing on equity,
one of the key features of market design is market access. The decentralised market
poses a greater challenge in this regard as it requires participants to have in place
physical contracts with buyers/sellers, whereas a centralised market guarantees
participants the opportunity to sell/buy from a single source. Naturally there are
some other challenges faced in a centralised market, such as risk management
through hedge contracts. However, hedge contracting is an easier form of risk
management where prices are publicly available than entering a market with the
prerequisite of having a physical contract.
On balance therefore the centralised market is ranked more highly on this criterion,
offering as it does, greater scope for inclusion of alternative and sustainable energy
sources to participate, as well as providing greater certainty and access to smaller
players – something which is considered in the following paragraphs.
Competition
It is generally considered that centralised markets are more favourable to competition
and the entrance of new participants than decentralised markets in the context of an
illiquid market. This is particularly so in markets with few participants because of the
difficulty that independents may face in trying to arrange counter-parties to buy/sell
energy from/to. A high proportion of independent participation is necessary in order
for a decentralised market to function effectively, though these independent
participants are not given the incentives to enter the market.
In contrast the centralised market gives all generator and supply companies access
to a market/supply for energy although there is likely to be a strong incentive to have
hedge contracts. The published pool price in a centralised market gives potential
new entrants a strong indication of the prices that are likely to be in the market. The
published price also gives existing participants a basis on which to negotiate efficient
hedge contracts. A decentralised market presents greater barriers to entry given the
42
present structure of the all-island market, as it would not provide transparent prices
or easy access to the market.
Therefore the centralised market performs considerably better than the decentralised
market against this evaluation criterion..
Conclusion and Proposed Market Model
The Regulatory Authorities are of the view that the centralised or gross pool market
model is the more appropriate choice for the SEM. Given the present structure of the
market on the island, it is considered that the centralised model will reduce barriers to
entry, provide more economic dispatch and will ultimately provide lower prices and
greater choice to consumers than would prevail under a decentralised model. A
centralised market is also more likely to maintain security of supply within the island
and is more likely to facilitate competition and will be more likely to induce new entry
than a decentralised market.
Finally, the centralised market provides more
opportunity for renewable and alternative generators to participate fully in the market.
Therefore the Regulatory Authorities having considered the above criteria are of the
view that the SEM should be a Gross Mandatory Pool.
In Chapter 3 of this paper the case for a capacity payment mechanism has been
made, and the Regulatory Authorities are seeking response to matters which will
facilitate the development of an appropriate capacity payment model. It is correct to
note that the two market variants outlined in Chapter 5 may each reasonably operate
either with or without an explicit capacity payment mechanism. To that extent the
consideration of the models does not depend further on whether they are more or
less suited to a capacity mechanism.
6.3 Evaluation of Markets; Self-Commitment –v- Central
Commitment
The trading arrangements for a gross pool or centralised market can take many
different forms that are distinguishable by their various features. Though there is no
single “correct” design, it is important that the features fit together to create a market
design that is internally consistent. The Regulatory Authorities have narrowed the
market design options to two specific models which can meet the stated objectives
and which are believed to be internally consistent. The key difference between the
market types is that one is a gross mandatory pool with self-commitment, short gate
closure, half hour optimisation and ex-ante pricing, whereas the alternative is a gross
mandatory pool with central commitment, 24-hour optimisation and ex-post pricing.
The remainder of this section evaluates the differences between these two models.
The following table show a summary of the evaluation results.
Security
of
Stability
Supply
GMP
with
Med
Self
Commitment
GMP
with
High
Central
Commitment
Low/Med
Efficiency Practicality Equity Competitive
High/Med
High/Med Med
Low
Med
High
High
Med
High
43
Security of Supply
The self-commitment market is dependent on generating participants achieving
feasible running schedules through the offers they submit. Generating participants
are also required to make commercial decisions about their plant through their offers.
The short gate-closure time in the self-commitment market means that the TSO
would have a shorter window to ensure that the market is dispatched in a secure
manner. The central-commitment market requires the participants to bid once a day
with a gate closure time of, say, 12 hours before the trading day begins. This long
gate closure provides the TSOs with a greater flexibility to ensure that the system is
dispatched in a secure manner.
Overall, the central commitment model is ranked higher than the self commitment
model on this evaluation criterion because it presents a more stable market, reduces
some barriers to entry is lower cost to implement and operate than a self commitment
market.
Stability
The centralised market may be considered to be more stable, as control of dispatch
is retained centrally, hence system operators will have a clear view of indicative
dispatch and take into account system stability issues. The centralised market does
not require participants to offer dynamically (within day in response to market
conditions), so this too will increase the stability of the market. The decentralised
market on the other hand relies on the “networked” information mechanism described
earlier to ensure that correct dispatch occurs, thus dispersing information among the
participants and relying on each individual generator to ensure technical feasibility of
bids.
On balance therefore the central commitment market is ranked higher in relation to
ensuring stability of the system.
Efficiency
The self-commitment market is based on the premise that generating participants are
best placed to make decisions about the commercial operation of their plant. For a
self-commitment market to work effectively it is a prerequisite that all participants
operate in a competitive manner. As well as this both generation and demand
participants have the opportunity to respond dynamically to any changes in the
market to ensure that the market is efficient. In a liquid market that is functioning
effectively self commitment should achieve the highest result against this evaluation
criterion. However, as mentioned earlier there are concerns as to the liquidity of the
market that could mitigate against this.
The central-commitment market requires a central operator to dispatch the market
efficiently based on information (offers) they possess about each generator. Since
the knowledge of the central operator in any market is imperfect the dispatch will
never be completely efficient therefore the central commitment model is ranked lower
against this criterion.
However, it is accepted that a central operator can achieve a high level of efficiency
provided that the market is dispatched using suitable optimisation tools, and that the
cost and complexity of achieving market dynamism in the self-commitment model
44
may not be justified against any benefits this might give against a market subject to
central dispatch.
Practicality
The dynamic nature of the self-commitment market requires participants to submit
offers regularly to achieve a feasible operating schedule. This also places increased
requirements on the Market Operator as a greater degree of redundancy has to be
built into the associated IT systems to ensure system security. The self commitment
market would require a large number of pre-dispatch runs to provide indicative
information to market participants.
Pre-dispatch runs do not require the same level of system redundancy in a central
commitment market. In addition the central-commitment market does not require the
same level of interaction between the Market Operator and the participants.
Consequently, both the costs to market participants and operators are lower and
ultimately reduce the costs faced by final customers. This is a major factor in the
economic case for the market, and is key to the regulatory approach to the SEM.
Consequently, the central commitment model scores considerably better on this
evaluation criterion compared to the self commitment model.
Equity
A gross mandatory pool with central commitment presents fewer barriers to entry to
new entrants than a gross mandatory pool with self commitment. First central
commitment reduces the administrative cost and system requirements for
participants. In addition, as outlined in earlier, capacity payments will give added
assurance around revenue adequacy thereby reducing barriers to entry. Both
markets will work and may even deliver the same result in theory. However, a market
design that reduces cost and risk to participants is more likely to find favour with new
entrants.
Therefore the central commitment model is evaluated as more favourable in relation
to this criterion.
Competition
Both central-commitment and self-commitment in a centralised market have visible
prices for energy aiding participants to negotiate financial hedge contracts that
accurately reflect the market value of energy. The central commitment model is
somewhat more favourable to potential new entrants because of the reduced
volatility of prices relative to the self-commitment market. Reduced volatility means
that the risk premium faced by potential new investors is reduced. Ultimately a
market with more independent generator/demand participants will be more
competitive than a market with a small number of vertically integrated participants.
Overall both models are considered equal in relation to the development of
competition.
Conclusion and Proposed Market Model
The Regulatory Authorities propose that the SEM is a central-commitment market. It
is accepted that the self-commitment market may lead to a slightly more efficient
dispatch than the central-commitment market. However, when the increased
implementation costs, operational costs to Market Operator and costs of participation
45
of a self commitment market and the size of the market are considered, the
efficiencies may be substantially eroded.
The central commitment model is also considered to provide greater system security
given current market conditions as well as providing greater opportunity for new entry
by removing barriers to such entry. While the central-commitment market when
combined with ex-post pricing does not have the same dynamic features that would
encourage demand side bidding, this can be mitigated by including design features
such as indicative pricing, which can be harnessed to facilitate demand side
participation. Further consideration will have to be given to both these issues when
developing the detailed rules.
The Regulatory Authorities believe that all the features of the centralised commitment
market are consistent and that there are no features that should adversely affect
system security or stability of the market. Therefore based on market stability,
competitiveness and the prospect that a gross mandatory pool with central
commitment and capacity payments will further reduce barriers to entry the
Regulatory Authorities favour this high level market design for the SEM
6.4 Conclusion
This section sets out the reasons for the preferred model of a gross pool market with
central commitment, ex post pricing and 12 hour gate closure. Respondents are
invited to indicate whether they agree with the preferred model. If alternatives, or
individual alternative design features, are considered preferable, the Regulators
would welcome an explanation of these along with a demonstration as to how any
alternative models are internally consistent.
46
7 Market Accessibility
7.1 Renewables and CHP
The Regulatory Authorities are committed to developing a market which will provide a
competitive environment that will foster the development of renewables and CHP. As
both CHP and renewable generators provide economic benefits, they will be
rewarded accordingly. As CHP and wind generators have lower variable cost of
production, the market price these generators receive for their electricity will reflect a
relatively higher fixed cost recovery compared to thermal plant. This should result in
CHP and wind generators being dispatched under the normal operation of the market
ahead of conventional plant.
Some features, (e.g. the special operating parameters of CHP), may require
additional consideration within the SEM. The Regulatory Authorities invite comments
and proposals in this regard in response to this paper.
Priority Dispatch
The Regulatory Authorities recognise that the market design must give effect to the
EU Renewables Directive provision regarding priority dispatch.
The European Union Renewables Directive states;
“Without prejudice to the maintenance of the reliability and safety of the grid, Member
States shall take the necessary measures to ensure that transmission system
operators and distribution system operators in their territory guarantee the
transmission and distribution of electricity produced from renewable energy
sources”.1
Priority dispatch in essence means that there will be no impediment to a renewable
generator exporting power, whenever they wish, subject to system security and
stability.
While such arrangements must be facilitated it is the view of the Regulatory
Authorities that renewable generators who opt to avail of priority dispatch must not be
allowed to set the price in the market. Renewable generators are therefore afforded
the choice of opting for priority dispatch and becoming price takers or alternatively
they can fully participate in the market and have price setting capabilities.
Two options for dispatching renewables, which could give effect to Article 7 of the
Directive as stated above, are outlined below;
A.
PRICE SETTING
Dispatchable renewable generators who have completed the relevant commissioning
test will be permitted to submit bids to the Market Operator for dispatch in the same
way as any other generator. This allows the renewable generator to set the price.
However, they run the risk of not being dispatched if their offer price is too high.
1
Article 7, Directive 2001/77/EC
47
B.
PRICE TAKING
The offers of dispatchable renewable generators will be automatically set at the
lowest price offer received by the Market Operator for that trading period. This
ensures that renewables will always be dispatched, subject to system security
constraints, and will always receive the market clearing price.
Intermittent plant (e.g. wind) will be required to satisfy a commissioning test in order
to be deemed dispatchable under option A above. This is likely to require a
forecasting ability to ensure they are available according to their quantity bid.
A renewable generator must confirm in writing to the Market Operator on an annual
basis whether it wishes to avail of option A or B, this is to be fixed for the following
year.
C
DE MINIMIS LEVEL
The Regulatory Authorities have also considered the issue of small-scale generation
operating within the market. It is proposed that generators below a de minimis level
will not be required to provide offers to the market. However such generators may
elect to participate in the market by providing offers. It is proposed to apply a de
minimis level of 5MW in the SEM above which generators will be obliged to provide
offers. However, in the case of price takers such offers will be standing offers as
outlined under B. Price Taking above.
7.2 Emissions trading
The European Union (EU) Directive on emissions trading (2003/87/EC) established a
EU-wide emissions trading scheme (ETS). The pilot phase of the EU ETS is from
2005-2007, with the second phase coinciding with the Kyoto period, 2008-2012.
Energy activities covered include combustion installations with a rated thermal input
exceeding 20 MW (excepting hazardous or municipal waste installations); mineral oil
refineries and coke ovens.
During the pilot phase, member states are required to allocate at least 95% of
allowances (representing one tonne of CO2 emissions) to participating installations
free of charge (90% during the 2008-2012 period). Participating installations will be
required to purchase any emissions requirement above this grandfathered allocation
or pay the penalty price.2 The EPA has recently allocated 74% of allowances to
generating plant in Ireland. The exact allocation in Northern Ireland is yet to be
determined however it is anticipated that it should be similar to that or Ireland.
The fixed nature of the cap under emissions trading means that the value of the
allowances is included in the costs of production. This in turn gives rise to an
opportunity cost of additional production since producing another unit of the good
needs allowances that must either be purchased or obtained internally e.g. by
installing abatement equipment. As such emissions trading will force up the SRMC
for generators using fossil fuel and it is anticipated that generating units subject to the
scheme would include the cost of carbon in their bids into the market.
2 €40 per tonne of CO2 for the 2005-2007 period and €100 per tonne for the 20082012 phase.
48
Emissions trading puts a value on the externalities caused by fossil fuel
burning. Because the price of production from fossil fuel sources relative to
renewable sources will rise. This will drive up the price received by all
generators, in which case renewables, such as wind, will become more profitable and
in turn more attractive to investors. With respect to the electricity trading regime we
must devise a market that has no inherent carbon distortions either between north
and south or between east and west. The Regulatory Authorities invite comment
from interested parties on this issue.
7.3 Demand Side Participation
Demand side bidding will be accommodated in the SEM design. At present it is
proposed that any purchaser of electricity may participate in the market, subject to
normal rules of participation.
A key decision in relation to demand side bidding will be that of ex-ante versus expost pricing. Under ex-post pricing, signals to demand side bidders are weakened
and participants’ responsiveness will be determined by indicative pre-dispatch
schedules. In this case demand side bidding may only become attractive during
more predictable periods such as the winter peak. Further consideration will have to
be given to demand side bidding at the detailed design stage to address price
certainty for demand side bidding. One possibility is to incorporate some rules into
the capacity mechanism for demand side participation.
7.4 Market Power
The Regulatory Authorities recognise that dominance and market power must be
addressed for the SEM to function effectively.
Concerns have arisen that participants in possession of market power will have the
ability to raise market prices or that they have the potential to select prices that are
sufficiently low to prevent profitable market entry.
One of the key issues the SEM must address is that of attracting new investment to
the Irish market. In the presence of significant market power potential new entrants
may perceive a high level of risk, even if the economic evaluation of an investment
were otherwise favourable. The mitigation of market power is therefore an area on
which the Regulatory Authorities will place strong emphasis and will form the basis
for a separate program of work.
Some of the options to mitigate market power include; (a) atomistic privatisation, (b)
disaggregated government owned utilities, (c) vesting contracts, (d) rule based
regulation of existing companies.
49
8 Conclusions
In conclusion, the Regulatory Authorities have identified and evaluated available
market models. As an initial step the Regulatory Authorities posed the question
whether the SEM should adopt a centralised or decentralised market. Secondly the
Regulatory Authorities considered whether the SEM should include an explicit
capacity payment mechanism in the SEM. Finally, further consideration was given to
the issue of unit commitment and price formation within the SEM.
The Regulatory Authorities have considered the various design options in the context
of maintaining security of supply, providing a reasonably stable market to participants
and consumers, designing a market which is efficient, economic, practical and
adaptive while at the same time encouraging new entry and fostering competition,
having due regard for the environment.
Having carefully considered the high level market design and the objectives of the
SEM the Regulatory Authorities conclude that given present market conditions on the
island it is preferable to proceed with a gross mandatory pool which is dispatched
under centralised commitment utilising ex-post pricing, explicit capacity payments,
with constrained on and off payments subject to further consultation on intermittent
generation, CHP and pumped storage. It is the view of the Regulatory that this will
provide a practical, effective and deliverable trading model for the Single Electricity
Market.
On the basis of this analysis it is the preferred model to take forward to detailed
design, subject to the comments and input of interested parties over the course of
this consultation and review period.
50
Appendix 1.
Existing Markets on the island
This Section of the paper outlines the current trading arrangements in Ireland and
Northern Ireland. A high level overview of the MAE objectives and design and
supplementary measures relating to generation adequacy and dominance is then
provided.
Transitional Trading Arrangements in Ireland
Market Design Overview
The existing trading arrangements for electricity were established on foot of a Policy
Direction issued by the then Minister for Public Enterprise to the Commission for
Energy Regulation (‘the Commission’) on July 26th, 1999 in accordance with Section
9(1)(a) of the Electricity Regulation Act 1999 (‘the ERA’). These transitional
arrangements provide for a bilateral contracts market with an imbalance mechanism
whereby participants can trade energy and balance out their uncontracted energy
needs with ESB Power Generation (‘ESBPG’). The rules for trading and settlement
under these arrangements are set out in the Trading and Settlement Code.3 ESB
National Grid (‘ESBNG’) currently performs both the market and system operator
functions. The System Settlement Administrator (‘SSA’), a unit within ESBNG,
performs the market operation and settlement function.
Dispatch, constraints and pricing
Under this regime generators nominate to the Transmission System Operator (‘TSO’)
the schedule of energy they wish to produce for trade a day ahead of real time
operation. In addition, incremental and decremental prices are submitted for variance
from this desired level of output. In carrying out the central dispatch role, the TSO
endeavours to adhere to generator nominations. However, inevitably this is not
always feasible due to system constraints, changes in plant availabilities and/or
changes from forecasted demand. The TSO selects the lowest incremental price bids
to increase generation and the highest decremental price bids to decrease
generation to meet fluctuations in load and system security requirements in real time.
In addition to these prices, start up costs, idling price, availability, minimum up and
down times and minimum generation levels are submitted to ESBNG.
At the end of the trading day, and prior to the submission deadline for ex post
bilateral contract nominations, generators and suppliers are provided with information
by the System Settlement Administrator (‘SSA’) to afford them the opportunity to
trade out imbalances amongst themselves. Any remaining imbalances are traded in
the imbalance market. Under the Policy Direction, purchases of energy in this market
are charged the ‘top up’ price and the ‘spill’ price is received for sales of energy.
Energy prices are primarily set under the terms of bilateral contracts between
suppliers and generators. In the imbalance market the top up price is set ex-ante by
the Commission. The top up prices in each half hour trading period is calculated as
ex-ante estimates of ESB PG’s avoidable fuel cost plus a capacity element weighted
according to the expected loss of load probability (‘LOLP’). These prices average out
to the best new entrant cost (‘BNE’) over the year. The spill price is set ex-post and is
defined as the highest decremental price of any unit on in the ex-post unconstrained
3
This can be found on the Commission’s website at www.cer.ie.
51
schedule (‘EPUS’) that can be decremented. The spill price contains a capacity
related element, which is paid under certain circumstances- the capacity related spill
price (‘CRSP’)- and is floored. In the event that the spill price exceeds the top up
price in a given trading period, the top up price is re-setting by the spill price. These
market prices are not location specific and at present a locational signal is provided
to generators via the Transmission Use of System charge (‘TUoS’) which varies with
location4 and locational loss factors. TUoS charges are derived based on the
dominant reverse MW-mile method and transmission loss factors are calculated
based on marginal loss factors.
Ancillary Service Provision
The TSO is responsible for procurement of ancillary services. The TSO’s objective
here is to maximise the scope of competition to supply the services where this is
possible. Under the Grid Code dispatchable generators are required to have the
capability to provide operating reserves and reactive power when instructed to do so.
The provision of these services is covered by contract with the TSO, the terms of
which are approved by the Commission. Black start is acquired under regulated
contract. Interruptible load, a type of operating reserve supplied by customers, is
paid for under a regulated rate that customers can apply for. The costs of provision
of ancillary services are recovered under TUoS from demand customers.
In addition to the above, demand customers can provide an ancillary service under
the ‘interruptible load’ service to the TSO. Under this service customers that can
withstand unplanned and instantaneous interruptions to their supply are paid by the
TSO for the amount of energy they make available for interruption. Contracts for the
provision of this service are awarded through a competitive tendering process.5
Demand Side Participation
At present demand customers do not participate directly in the market and
participation is through specific demand reduction schemes offered by suppliers.
Under the Winter Peak Demand Reduction Scheme (‘WPDRS’) customers of
independent suppliers are rewarded via a rebate from their supplier for reducing their
usage relative to historical usage over peak weekday hours in the winter months.
ESB PES customers can avail of a similar scheme, the Winter Demand Reduction
Incentive (‘WDRI’,) although the rebate received here is not related to historical
usage. In addition to the above, under the Powersave scheme customers receive a
payment from ESB Power Generation in the event that they are called on to do so,
must reduce load.
Current Trading Arrangements in Northern Ireland
Industry Structure Background
In 1992, the state-owned electricity industry was privatised under the Electricity
(Northern Ireland) Order 1992. The network and supply functions were vested in
4
Further information on the transitional trading arrangements please refer to the following
documents which can be found on the Commission’s website (www.cer.ie.): Helicopter Guide
to Trading and Settlement (ESBNG), Guide to EPUS (ESBNG), Final Proposals for a
Transitional Electricity Trading And Settlement System (CER/00/02).
5
Additional information on the above can be viewed on the ‘’System Operations’ (Ancillary
Services) page of ESBNG’s website (www.eirgrid.com).
52
Northern Ireland Electricity (NIE) plc and the generation plant was sold to
independent investors. Licences were issued to NIE for transmission & distribution
and public electricity supply, along with others to independent Second Tier Suppliers.
Under the trading arrangements put in place at privatisation, all generation was
contracted under long-term Power Purchase Agreements (PPA’s) to NIE’s Power
Procurement Business (PPB) and sold on to suppliers at a regulated Bulk Supply
Tariff (BST). Under these arrangements all customers were free to choose their
supplier, but all suppliers had to buy their power from NIE’s Power Procurement
Business (PPB) thus effectively constraining competition.
In 1999 new interim trading arrangements were introduced with the implementation
of the EU Directive: Internal Market in Electricity (96/92/EC). This Directive in aiming
to introduce competition required that suppliers no longer had to purchase their
generation requirements from PPB. The lifting of this constraint meant that suppliers
could therefore contract at a negotiated price with Independent Power Producers
(IPPs) to meet the demands of their customers. The sources of independent power in
NI have ranged from out of contract Ballylumford & Power Station West sets, the
Moyle Interconnector and now ESB Coolkeeragh in 2005, with the remaining NI
generation plant still contracted to PPB. These interim trading arrangements are still
in place today and have facilitated the opening of the retail market to 35% of
customers in 1999, and to 60% of customers in 2005 under the IME Directive. The
Northern Ireland Authority for Energy Regulation (NIAER) regulates the industry,
under the power of the Electricity (Northern Ireland) Order 1992, as amended by the
Energy Order 2003.
Wholesale Market Arrangements Overview
The current interim trading arrangements, as set out in the Interim Settlement Code6,
are based on the scheduling and dispatch of bilateral contracts. While SONI acts as
the market and system operator, settlement is facilitated by PPB, who sells Top-up
energy at the regulated BST price and buys Spill energy at a regulated price based
on the avoided fuel cost.
Under these arrangements, generators make nominations to the System Operator for
Northern Ireland (SONI) for each of their generating units for a trading day by gate
closure on the previous day. Dispatch by SONI is based on must run nominations by
IPPs and imports nominated across the Moyle Interconnector. PPB contracted plant
then makes up the remainder of the dispatch. IPPs may submit bids for additional
dispatch to be placed in the merit order against PPB plant.
Ancillary services are provided for in the PPB contracts, and are funded through
charges levied by SONI on all customers. IPPs are also paid to provide Ancillary
services at a fixed regulated rate. Demand side participation is not currently active in
the NI market through any central market mechanism.
Current interconnector trading arrangements
In the context of the island, there are two electricity interconnectors, one between NI
and RoI (North-South) and one connecting NI with Scotland (Moyle). Each year the
System Operator Northern Ireland (SONI) and ESBNG hold an auction to allocate
capacity to the market for flows North-South and South-North respectively. Auctions
on the Moyle interconnector are held after NIAER consultation with the industry on
allocation procedures, which takes into account the possible effects of recent market
developments e.g. new BETTA trading rules in GB.
6
www.soni.ltd.uk
53
North-South Interconnector
The North-South interconnector currently has a net transfer capacity of 330MW in a
north-south direction. In recent years the net transfer capacity in a south-north
direction has been effectively zero for the majority of the time. This has been due to
system security issues and transmission constraints. In the past, all north-south
capacity has been allocated on a yearly product basis, with an additional 2-year
product being introduced in the 2005 auction.
Superpositioning on the North-South interconnector was introduced in April 2003,
due to constraints on the physical transfer capacity of the interconnector and is being
administered by ESBNG. This mechanism of netting off trades in opposite directions,
by making available short-term capacity allocated two days prior to the trading day,
maximises the utilisation of the physical transfer capacity of the interconnector.
In addition, there are arrangements in place between SONI and ESBNG, for marginal
trading and reserve sharing, which minimise the costs of dispatching the
interconnected systems and maintaining system security.
Moyle Interconnector
The Moyle interconnector to date has been used solely for import purposes. It
currently has 125MW out of an available 400MW contracted to PPB to facilitate its
import contract with Scottish Power. The remaining 275MW are auctioned annually to
appropriately licensed and authorised market participants. Moyle capacity to date has
been auctioned by products that vary by duration, namely one, two and three years.
54