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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