The Integration of Electricity Markets in Ireland under the ISO Model

The Integration of Electricity Markets in Ireland under the ISO Model Paul Conlon ESB International 1. Introduction In November 2004 the respective governmental departments of Ireland and Northern Ireland signed the Development Framework which allowed for the formal programme of work by the two Regulatory Authorities to commence. In June 2005, the respective transmission system operators (both Independent System Operators) in the Republic of Ireland and Northern Ireland signed a formal Memorandum of Understanding, underlining their commitment to combine the skills and resources to work jointly on a number of important initiatives as part of the all-island project. The Single Electricity Market (SEM) Programme was subsequently established to focus on the delivery of a single wholesale electricity market for the island, which in turn has led to the formation of the All-Island Market for Electricity (AIME). SEM came into effect from 1st November 2007 as a day ahead, dual currency, gross mandatory pool and was hailed by EU Energy Commissioner Andris Piebalgs as "a significant contribution to the construction of the internal energy market" in Europe. Before SEM opening the Republic of Ireland operated a bilateral contracts Model with regulated top-up and spill arrangements, whereas Northern Ireland operated a Single Buyer Model for most generators (although some bilateral arrangements were in place for others ). This paper will outline the experience gained from the integration of the two markets, from an incumbent utility s perspective (ESB). The functioning of the market since start-up will be discussed, and comment made on what has worked to date, what could be developed further, and what, if any, impact the new design has had on market consolidation and competition. On the supply side, demand met by ESB has decreased gradually since 2005 to approximately 51% before the launch of the Single Electricity Market. Until very recently (April 2009) the majority of the competition in the supply business has been evident in the commercial sector, however this is changing with the advent of market campaigns from independent suppliers aimed entirely at the domestic sector. As part of market liberalisation process ESB has been restructured into heavily ring-fenced business units. These business units primarily cover ESB Power Generation (PG), ESB Networks, (which owns, but does not operate the transmission network and is both distribution network owner and operator), and ESB Customer Supply In addition, ESB National Grid became a legally separate company EirGrid plc, which took over the role of transmission system operator (under the ISO model) in July 2006. A diagram highlighting the structure and main participants in the electricity market in the Republic of Ireland is shown below. Aughinish Alumina 1.1 Republic of Ireland Electricity Market Electricity consumption in the Republic of Ireland equates to approximately 29TWh with peak demand of 5.1GW (2008) from generating capacity of 7.5GW. As of April 2009 the year on year generation fuel mix consists of 54% Gas, 17% coal, 10% distillate, 10% wind, 5% oil and 4% hydro/pumped storage. Wholesale Market competition has been progressively introduced since February 2000 and Retail Market competition has been introduced progressively with full market opening achieved in February 2005. ESB as the state owned vertically integrated utility is the major generating asset owner with approximately 50% of dispatchable generation; this is expected to fall to 40% by 2012. Figure 1. RoI Market Operators The operating relationship between the incumbent and transmission asset owner (ESB Networks Ltd.) and the Independent System Operator (EirGrid Plc) is managed via an Infrastructure Agreement. ESB Networks and EirGrid have a successful track record of working together to design and construct transmission network infrastructure in RoI. Under the terms of the Infrastructure Agreement which has been in existence for a number of years, each has defined

responsibilities, with transmission system operator being responsible for identifying requirements and managing the planning permission and consents process, before detailed design and construction is carried out by the asset owner. This process is outlined in the diagram below. Distributed Generators EirGridProcess ESB Process Planning Identify need & possible Solutions EirGridCA & issue IP Planning Application Landowners Wayleave / Landowner Discussions Resource/Material Planning Issue CPP Figure 3. NI Market Operators Design/construction Construction / Commissioning/ DOF Cert. of Acceptance Design Review Detailed Design & Material Procurement Project Agreement Scoping/Programme Figure 2. Infrastructure Agreement Process in RoI Develop SoW / Programme & issue PIP / ESB CA 1.2 Northern Ireland Electricity Market Electricity consumption in Northern Ireland is approximately 9TWh with peak demand of 1.7GW (2008) from a generating base of roughly 2.3GW consisting primarily of gas and coal plants with 0.3GW of renewable energy sources (mostly wind). Northern Ireland Electricity (NIE) was privatised in 1998 resulting eventually in three major power generating sites in Northern Ireland currently owned by Premier Power, AES and ESB. Ownership of the transmission system remains with NIE a wholly owned subsidiary of the Viridian Group. NIE Energy s Power Procurement Business (PPB) is responsible for managing a portfolio of power purchase agreements in Northern Ireland with a total contracted generation capacity of 1.53 GW. Electricity retail supply is fully open to competition as of November 2007 (SEM opening), however there are currently no independent suppliers offering tariffs to residential or small commercial customers. The NIAUR has a programme of work established to implement the required central market infrastructure that will facilitate customer switching within the next 2 years. Although EirGrid is now the transmission system operator in both Northern Ireland and the Republic of Ireland, and both jurisdictions operate under the ISO model of ownership unbundling, there are some differences in the operations of the two ISO s. For instance EirGrid is responsible for transmission protection, permitting, development and maintenance and transmission planning, while this is not the case with SONI. 1.3 Key Features of the Single Electricity Market The market design has some features reminiscent of markets in other jurisdictions, (such as Nordpool, the Eastern Australian market and the former British pool) but on the whole the SEM is a unique dual currency ( GBP and ) inter-jurisdictional market (given its international and mandatory character) that comes under the governance of both the Commission for Energy Regulation and the Northern Ireland Authority for Utility Regulation. The Single Electricity Market Operator (SEMO) is the market operator responsible for the administration of the SEM. The organisation is a contractual joint venture between EirGrid and SONI. A high level overview of the operation of the Single Electricity Market is depicted in Figure 4 below. The transmission System Operator for Northern Ireland (SONI) was initially held under the holding company of Viridian. As with the Republic of Ireland transmission structure, SONI operates as an ISO. SONI was subsequently acquired by EirGrid plc in 2008 (shortly after SEM market opening). Ownership of the transmission asset remains with NIE. A diagram highlighting the structure and main participants in the electricity market in Northern Ireland is shown below. Figure 4. Single Electricity Market High Level Overview

Gross Mandatory Pool Virtually all trade of physical electricity is conducted through the SEM pool and the opportunities for bilateral trading of physical power outside this pool are limited to small scale AER [Alternative Energy Requirement, a legacy market support arrangement for wind energy in Ireland] generators. Compulsory participation is limited to a 10MW minimum threshold; generators below this threshold can choose whether to participate in the pool or be treated as negative demand. Day Ahead Complex Bidding Price Maker Generators wishing to sell their electricity through the pool are required to submit their Commercial (10 Price/Qty pairs, start up and no load costs) and Technical (dynamic characteristics and availability forecasts) Offer Data to the Market Operator by 10:00 hrs on the day before the relevant trading day (D-1). Under the bidding code of practice generators must bid their short-run marginal cost, (SRMC), including the full opportunity cost of carbon, into the pool (this represents the market shadow price) as well as an uplift element representing start-up and no load costs. Based on the offer data submitted, the System Marginal Price (SMP) as the SRMC of the marginal generating unit, a single price for each half hour of electricity irrespective of transmission constraints or reserve, is established by the Market Operator. The SMP is determined as the summation of the Shadow Price and Uplift. Payments and Charges All generation units receive and supplier units pay the same SMP. There are however separate payments or charges for constraints and imbalances intended to compensate for dispatch which does not follow the merit order and to incentivise the following of dispatch instructions. Consequently all generator units are subject to central dispatch taking into account system constraints, reserve requirements and real time issues such as unplanned outages. Generators also receive a Capacity Payment for being available, irrespective of actual generation. The capacity payment is aimed at encouraging availability close to real time and is designed to compensate in part for a units fixed costs and encourage future investment into the market. In turn supplier units receive a capacity charge on the basis of its net demand for each trading period. Figure 5. Single Electricity Market Timeframes Market Power Mitigation As part of the development of the SEM, the regulatory authorities developed a market power mitigation strategy to prevent the abuse or distortion of the market by dominant players. The major focus of the market power mitigation strategy has been the imposition of Directed Contracts on all generators with what is considered a significant level of market power, the imposition of a licence condition on generators to adhere to a bidding code of practice and the establishment of a Market Monitoring Unit to monitor participants bidding behaviour. The directed contracts mandate that generators with significant market share must enter into forward contracts with suppliers for a specified volume at a price based on a pre-determined formula. It is the aim of the directed contracts to reduce the market power of those generators so that capacity is not withheld, nor bids submitted above competitive levels to affect prices. To date ESB Power Generation and NIE Public Procurement Board (a subsidiary of the Viridian Group) have been mandated to enter into directed contracts. Participants may also enter into Non Directed Contracts. Both sets of contracts are financial in nature, known as Contracts for Difference and are used as a means to hedging price exposure in the pool. Operation of the Contracts for Difference in the SEM is illustrated in Figure 6 below. Both sets of contracts are let quarterly via an auctioning process. Other payments for generators include Constraint Payments, an Uninstructed Imbalance Payment and Make Whole Payment. Imperfection Charges are applied to Suppliers to recover the Constraint and Uninstructed Imbalance payments. An overview of the timing of the various bids, payments and charges is shown below in Figure 5.

Supplier pays extra to generator Price ( /MWh) 100 80 60 40 20 0 pay pool 01:00 net payment 05:00 09:00 Pool Price Strike Price 13:00 pay pool 17:00 Figure 6. Contracts for Difference in Operation Generator pays difference to supplier net payment The volume of directed contracts offered to date is shown in the Figure 7. Quarter Q4 2008 Q1 2009 Q2 2009 Q3 2009 ESB PG Quantities Baseload Mid- (MW) Merit (MW) Peak (MW) 21:00 NIE PPB Quantity Baseload Mid- (MW) Merit (MW) 244 135 480 0 0 0 280 36 489 0 0 0 237 110 n/a 0 107 n/a 132 223 n/a 0 233 n/a Figure 7. Directed Contract Volumes Peak (MW) Under the contracted auction process three product types were offered as outlined in Figure 8 below. Contract Start End Applies Type Time Time Baseload 24 hours per day All year Mid- Merit* 07:00 23:00 Business days and non-business days 1 Peak # 17:00 21:00 6 winter months * Previously 07:30-23:00 # Previously 16:30 20:00 Figure 8. Directed Contract Volumes Average strike prices for the various Directed Contracts by product are given in Figure 9. 1 For non business days, under the Mid Merit 1 contract, only 80% of the contracted volume is applicable Contract Type Average Strike Price Baseload 91.30 Mid-Merit 1 102.77 Peak 162.20 Figure 9. Directed Contract average Strike Prices by Product Interconnection The Irish electricity market is only lightly interconnected with Great Britain. In this regard the market can be considered as a small isolated system on the periphery of Europe. Prior to the SEM start-up an interconnector existed between the two jurisdictions on the island however since integration this is no longer treated as an interconnector but is instead treated as part of the transmission network. The Moyle interconnector between Northern Ireland and Scotland, with a nominal capacity of 500MW links the SEM to the British power market. Under the SEM trading and settlement rules, interconnector units are treated as a special type of generator. Such units must submit commercial offer data to the Market Operator as with normal generator bids (excluding no load and start up costs). Future interconnection with GB (and further afield if the situation arises) will be treated in a similar vain. At present two additional interconnection projects of 1000MW in total nominal capacity are planned. Impact and Treatment of Renewable Energy Currently treatment of renewable energy generators is, based on the trading and settlement rules. Given that wind is, and will be, the dominant source of renewable energy in Ireland, a wind generator (as a case in point for the treatment of renewable generating units) may register as any of the following with different bidding rules applying for each: - A Variable Price Maker (VPM) - A Variable Price Taker (VPT) - An autonomous generator unit - Or as negative demand With its extensive resource, both north and south, electricity derived from wind is currently having a significant impact on the Irish electricity system. This will only increase in future years as the proportion of wind generating capacity connected to the grid grows. As a small isolated system this will have severe implications for the operation of the grid as the additional capacity is added. To date over 10% of the generating capacity is from renewable sources (primarily wind) this amounts to one of the highest penetrations of wind energy in Europe.

There is also the added complexity of two different support systems for RES (Feed-in tariff in the Republic of Ireland and Renewables Obligation in Northern Ireland) within the two jurisdictions. As energy generated from wind plays a greater role in the market as the main contributor for the meeting of renewable targets set out by the respective governments and the EU, a joint policy initiative is essential for its treatment under the SEM. Both regulators are currently undertaking such an initiative, in order to consider the specific treatment of wind in the SEM. 2. Market Performance To-Date Since its opening in November 2007, the SEM has dramatically changed the nature of the electricity markets in both the Republic of Ireland and Northern Ireland. The primary objective in establishing the SEM, as defined by the regulatory authorities, was to develop wholesale electricity arrangements that deliver an efficient level of sustainable prices to all customers for a supply that is reliable and secure in both the short and long term and on an all-island basis. This primary objective was 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 - enabling demand side management Figure 10. SEM Load Duration Curve Nov 07-08 (Source: SEM Committee Annual Report, March 2009) The load duration curve does not differ significantly from that experienced prior to SEM. For only a small proportion of the time is demand above 5GW, and with nearly 10GW of capacity on the system, this would indicate a significant reserve margin, notwithstanding system constraints and scheduled/unscheduled outages. Figure 11 shows the reserve margin (orange line) calculated as a weekly moving average across the period. While the capacity margin does not get particularly tight at any time over the period, the chart clearly highlights price spikes at times of tightening margin an inverse correlation. In considering whether these objectives have been achieved, albeit at a very early stage of the market it is useful to consider several performance indicators. Capacity Margin Figure 10 illustrates the load duration curve (% time that load/system demand is above a certain level) for the SEM over the first 12 months of its operation. Figure 11. Capacity Margin against SMP, (Source: Market Monitoring Unit Public Report 2009) In this regard it would appear that the objective of ensuring a secure supply of electricity has been achieved, in that the system margin has remained within comfortable limits throughout the period to Dec 2008. Price Volatility Figure 12 below shows the average daily profiles (shadow price, uplift and price spread, as well as demand load) over the first 12 months of market operation.

Figure 12. Average Daily Demand and Price Profile Nov 07 08 (Source: SEM Committee Annual Report, March 2009) The time weighted average SMP in 2008 was 80.6/MWh (demand weighted average was 84.6/MWh), although the highest hourly SMP values were considerably more than this. The maximum SMP during the year was 696.85/MWh occurring in October. The Price Duration Curve depicted in Figure 13 below shows the propensity for price spikes in the SMP. This clearly shows the vast majority of half hourly SMP s occurring within the 50-100/MWh band (approximately 70% of the time), with about 10% of half hourly trading periods yielding prices below 50/MWh. Figure 14. Ireland Versus UK (ELEXON) Electricity Prices (Source: Market Monitoring Unit Public Report 2009) The objective of sustainable pricing is therefore to some extent achieved (albeit that there are many other factors affecting the actual transaction costs. These are discussed further below. Other Price Determining Factors As an isolated system, relying heavily on imported fossil fuels, the SMP is particularly susceptible to changes in international fuel prices. The majority of dispatchable generation capacity within the SEM is gas-fired plant (>50% of total demand is provided by CCGT plants alone), therefore one would expect a significant correlation between SMP and gas price. Indeed this is observed in the below chart. Figure 13. Price Duration Curve Nov 07 Dec 08 (Source: SEM Committee Annual Report, March 2009) While it is not a direct measure of success, (against the stated objectives), the level of price spikes in the SEM is not excessive (it is comparable with other markets such as the UK wholesale market, BETTA (see Figure 14). The BETTA price when compared with the mean SMP averaged across a trading day is slightly flatter but not excessively so. Figure 15. SMP correlation with Gas Price (NBP) (Source: Market Monitoring Unit Public Report 2009) Even with regard to coal prices, a not insignificant correlation is demonstrated even though coal fired units within the SEM only make up about 20% of the demand delivered during the market s opening year.

Given the above correlation, we can conclude that the SMP is driven largely by international energy markets and therefore it is difficult to see what impact, if any, a specific market design or trading and settlement rules can have on costs to participants/suppliers, other than through ensuring minimal transaction costs and adequate margin exists so that at best the price will closely track international (NBP) gas price. Capacity Payment Mechanism (CPM) As a mechanism for incentivising investment in the SEM (efficient entry signalling) it is too early to tell if the capacity payment mechanism is or will make a significant contribution. There is certainly significant interest in developing new generation capacity on the island. However there are many other factors that may be contributing to this interest. If however we look at two general signals that investors tend to look for, stability and certainty would be key ingredients. An understanding of how these have played out in terms of the capacity payment might give an indication as to its likely effectiveness. Figure 16 highlights the capacity payment pots (being the total sum of monies available) made in the first year of operation in comparison to estimates of the hours of lost load. SEM. The Market Monitoring Unit was established to oversee issues in relation to market power abuse of all operators through the analysis of data submitted by market participants (i.e. Commercial and Technical Offer Data). In the initial period following market opening, several participants issued formal complaints in relation to the bidding strategy being undertaken by a number of generating units. The main cause of concern was that the generators were bidding below marginal cost and displacing other units from the merit order. In its deliberations the MMU agreed, that for one generator which was bidding in accordance with gas prices set under a legacy gas contract, this practice could continue due to the prohibitive costs of contract renegotiating. For the other generators clarification was issued as to how start up costs should be calculated and bid into the market. No other significant market power deliberations have been issued. With a total of 45 participants in the SEM, 13 having joined since market launch, the objective of promoting competition within the wholesale electricity market is certainly being met. There are however other factors that are contributing in this regard (such as regulatory agreements by ESB to reduce its market share through plant closures and divestment, as well as the significant level of renewable resource on the island, coupled with the challenging targets for renewable energy generation). 3. Conclusion In conclusion, the integration of the two electricity markets in Ireland has been a success; the market has operated now for over 18 months (with energy payments in excess of 4 billion / 3 billion sterling during that time), and there have been no major issues with regard to the operation and oversight of the market under the two jurisdictions (via the MMU). The MMU itself has not had to intervene in the market in any significant matters relating to market dominance. Figure 16. Capacity Payment Pots and Lost Load Estimates (Source: Market Monitoring Unit Public Report 2009) However, the consistency of the regulatory process governing the annual quantification of the payment (in relation to determination of the Best New Entrant Fixed Costs upon which the CPM is based) has been an issue for ESB and other market participants. A review of the process is being undertaken; however recent proposals by the Regulators suggest a reduction in the overall value of capacity payments across SEM. When this is taken together with a greater number of generators consuming from a decreasing pot, this increases the risk of uncertainty in the viability of major investments going forward. Market Power Mitigation and Competition Market power concerns and mitigation of any abuse of power was a key requirement during the development of the The process has not been without its teething problems however. Due to the huge complexity of the changes implemented, and the near real time nature of the market difficulties have been encountered. As mentioned previously the capacity payment setting has not been consistent and the transparency of the decision process surrounding it could be improved. Errors with the settlement process resulted in adhoc re-settlements of energy and capacity payments to market participants on a number of occasions, although these have now been overcome, indeed several new market settlement software roll outs have occurred without impacting the market. From an ESB (incumbent) perspective the failure to include sunset provisions in the measures aimed at market power mitigation, namely the MMU, bidding principles and the Directed Contracts process has been disappointing,

particularly in light of ESB s efforts to reduce market share in compliance with regulatory requirements. Finally, it should be noted that while the two markets have integrated successfully, the process is not complete. Trading rules for good electricity market design should take into account four main features: - Imbalances - Congestion management - Ancillary services - Scheduling and dispatch However a number of areas relating to the above features have yet to be addressed under SEM rules. These primarily relate to: - Principles of generation plant dispatch: Ireland is experiencing a huge investment in wind generation, and it is likely that in many cases such non-firm generating plants will connect to the system before the required transmission infrastructure is in place (resulting in constraints). At present under SEM rules such plant could be rewarded infra-marginal rent under the market schedule, contributing to an increase in short run marginal costs and potentially sending the wrong investment signals to the market. A regulatory consultation is currently under way to deal with this matter. - Ancillary services: These are currently still operated on a jurisdictional basis, although a policy paper seeking to harmonize the service has been published. - Transmission Use of System (TUoS) and related Transmission Loss Adjustment Factors (TLAFs): Jurisdictional TUoS charges remain in place, although a number of consultations have been held to establish a basis for a future all-island TUoS methodlogy. TLAFs are location specific for each generator, however there are concerns over their effectiveness and lack of transparency in their calculation. The regulators plan to investigate the TLAF methodology in line with the aforementioned review of TUoS.. - Retail market: Retail markets on the island are not harmonized and indeed policy and regulation are jurisdictional matters, however common goals between the two areas have been identified in relation to the Public Energy Supplier, supplier switching arrangements and codes of practice. Work is expected to begin this year in relation to harmonization of the retail markets. (and the integration/creation of a regional market between the UK and Ireland), it remains to be seen if the gross mandatory pool will survive or the market will move in line with BETTA towards a bilateral market. 4. Acknowledgements The author gratefully acknowledges the contributions of F. Egan, D. O Hara and C. Doran for their assistance on the original version of this document. 5. References [1] SEM Committee Annual Report, March 2009, Commission for Energy Regulation & Northern Ireland Authority for Utility Regulation. [2] Market Monitoring Unit Public Report, April 2009, Commission for Energy Regulation & Northern Ireland Authority for Utility Regulation [3] SEM Experience to date and the impacts for the future, Sean McGoldrick, General Manager, Single Electricity Market Operator [4] Making Competition Work in Electricity, 2002, S. Hunt, [5] Republic of Ireland and Northern Ireland Electricity Report, An ILEX Energy Report to ESBI, Feb 2009 6. Biographies Paul Conlon is a Senior Energy Analyst with ESB International. He holds a Masters in Chemical Engineering from Queen s University Belfast and an MBA in International Finance from the Smurfit Business School, University College Dublin. Paul specializes in providing techno-economic and strategic analysis to clients in the energy industry and has advised private corporations as well as government agencies and departments on a wide range of economic, commercial and regulatory issues. He has prior experience in policy development for EU ETS National Allocation Plans and Energy Efficiency in both the UK and Ireland. Paul is a member of the Institute of Chemical Engineers. It is clear that the development of the SEM is an ongoing initiative. There is no secondary trading market to enable participants to refine their hedge positions, and to date the regulators do not view this as coming under their charge, although some participants would welcome it. Looking further into the future, and given the likely coupling of the SEM with the much larger BETTA market,