SEM Regional Integration Project Working draft Description of HLD options for HLD Review Group Meeting (8 January 2014) 20 December 2013 Table Contents 1 Purpose of this document ............................................................................................................... 3 2 Topics for the High level design of energy trading arramgements ................................................. 4 3 Summary of options ...................................................................................................................... 19 4 Option 1: Adapted Decentralised Market ..................................................................................... 23 5 Option 2: Mandatory ex-post pool for net volumes ..................................................................... 27 6 Option 3: Mandatory centralised market ..................................................................................... 31 7 Option 4: Gross pool – net Settlement market ............................................................................. 35 8 Capacity remuneration mechanisms ............................................................................................ 38 9 Glossary ......................................................................................................................................... 43 10 Abbreviations ............................................................................................................................ 44 1 PURPOSE OF THIS DOCUMENT 1.1.1 This document is intended to provide a description of different High Level Design (HLD) options to inform discussions at the SEM HLD Review Group on 8 January 2014. The document represents work in progress and therefore should be considered as a draft rather than the final description of these options that will appear in the consultation paper. 1.1.2 The consultation paper itself will describe a number of distinct HLD options. However, there will still be scope to amend each option in relation to how it addresses each topic as a result of feedback through the consultation process. Any changes should not alter the overall objective of the HLD option. 1.1.3 This document is structured as follows: o Section 2 discusses of the main topics and choices to be addressed by any HLD for a set of energy trading arrangements; o Sections 3 to 7describe four HLD options for energy trading arrangements, including how each option addresses the main design topics; o Section 8 describes a number of possible approaches to Capacity Remuneration Mechanisms; and o Sections 9 and 10 contain a glossary of the terms used in this document, and a list of abbreviations. 1.1.4 Capacity Remuneration Mechanisms (CRMs) are not presented as an integral part of any HLD option. This is because the design of a CRM (where it exists) should take into account developments in neighbouring countries and the requirements of European state aid guidelines, as well as the HLD of the energy trading arrangements in the SEM. 1.1.5 This document is focused on differentiating between the options to inform discussions at the HLD Review Group on 8 January 2013. Therefore, it does not concentrate on some issues that will need to be considered for all the HLD options, inter alia: o how periodic intraday auctions could be combined with continuous trading o the mechanisms to help the TSO address non-energy issues in ensuring safe and secure operation of the electricity system 2 TOPICS FOR THE HIGH LEVEL DESIGN OF ENERGY TRADING ARRAMGEMENTS 2.1.1 This document differentiates between different High Level Design options with respect to how energy is traded in and across different market timeframes1; namely: 1 There are other possible ways of differentiating between energy trading arrangements. For example, they could be differentiated according to how constraints and ancillary services are treated within the results of the energy market. For example, co-optimising energy and reserves would be a different option to one where they are dealt with in separate markets or in separate ways. For the purposes of the revised SEM HLD, cooptimisation of energy and reserves has been ruled out as a possible option, and therefore we concentrate on differentiating between the options with respect to the trading within and across different timeframes (in line with the approach taken in the European Electricity Target Model). o Forward (FW) o Day-Ahead (DA) o Intraday (ID) o Energy Balancing o Imbalance or ex-post settlement 2.1.2 Ultimately it is the ex-post or imbalance price that all market participants will face in relation to volumes not settled in earlier markets. Therefore, the earlier markets act as a tool for market participants to manage risks and their exposure to the ex-post or imbalance price. It is the expectation of the imbalance price(s) that drives prices in the IDM, the expectation of the IDM and balancing prices that drives prices in the DAM and so on.. This means that the markets in different timeframes should be designed in a coherent way to allow efficient arbitrage of trading between them – i.e. the overall HLD needs to ensure that the market in each timeframe is ‘fit for purpose’. 2.1.3 The mechanism by which the TSO can procure energy for balancing supply and demand can take the form of an integrated process of scheduling and dispatch (as in the SEM today) covering all volumes, or a mechanism based around ‘simple’ bids and offers for residual (or net) volumes (i.e. a separate ‘balancing market’). 2.1.4 Table 1 lists the main topics (and associated choices) for describing how energy is traded in and across different market timeframes. In the rest of this section, we describe these topics and choices in more detail. 2.1.5 This section is intended to inform Sections 3 to 7, where we describe how each HLD option by the choices taken for each of these topics. Table 1 – Topics of the HLD options and choices under each topic Topic Sub-Topic Choices Participation in European markets for trading of energy in day-ahead (DA) and intraday (ID) timescales DA Portfolio vs. unit bidding o Net portfolio bidding o Gross portfolio bidding o Unit bidding Mandatory vs. voluntary o Voluntary o Mandatory Bid format o Simple o Block o Sophisticated ID Portfolio vs. unit bidding o Net portfolio bidding o Gross portfolio bidding o Unit bidding Exclusive vs. Non- exclusive o Exclusive o Non-Exclusive Bid format o Simple o Block o Sophisticated Process for reaching feasible dispatch position Starting point of dispatch o DA (and ID) nominations o IC schedule Bids to the TSO for balancing and dispatch o Complex bids o Inc’s and dec’s Timing of bid submission o At DA and updated continuously o At DA and updated at specific windows Imbalance/Pool settlement o Marginal imbalance price based on separate balancing mechanism o Ex-post unconstrained market schedule Arrangements for long-term trading Internal o Physical o Financial Cross-border o PTRs o FTRs 2.2 PARTICIPATION IN THE EUROPEAN ELECTRICITY MARKETS (IN THE DA AND ID TIMEFRAMES) 2.2.1 This topic covers the arrangements for trading energy between market participants in the Day-Ahead (DA) and Intraday (ID) timeframes. 2.2.2 The DA Market (DAM) is the European DA market coupling arrangements, based around a European Gate Closure (GC) expected to be at 1100 UTC on the previous day (D-1) for a trading day running from 2300 to 2300 UTC. Participation in this market is the only way at the day-ahead stage for market participants to access cross-zonal capacity to match trades. 2.2.3 The ID market (IDM) in this context means the European ID market coupling arrangements. It is assumed that participation in this ID market is the only way for market participants to access cross-zonal capacity at the ID stage. However, it may not be the only way in which market participants can adjust their scheduled position (as represented in their nominations). For example, it is possible that they could adjust their position through bilateral trades struck directly with another market participant, or by making changes within their own portfolio. 2.2.4 There are two issues that are common for both market timeframes: o the aggregation level of the bids to sell energy that are submitted in the DA and ID markets (‘portfolio vs unit’ bidding); and o the bid format 2.2.5 In addition, we distinguish between mandatory and voluntary participation in the DAM; and exclusive and non-exclusive participation in the IDM. PORTFOLIO VS. UNIT BIDDING (DAM and IDM) 2.2.6 This topic covers the aggregation level of the bids to sell energy that are submitted in the DA and ID markets. The main alternatives are: o Net portfolio bidding; o Gross portfolio bidding; o Unit bidding Net Portfolio bidding 2.2.7 Under net portfolio bidding arrangements, a market participant can send a single set of bids (or offers) for energy in a single bidding zone, covering both all of its production assets and any demand it is responsible for procuring on behalf of end- customers. For example a market participant with 100MW of demand and 120MW of generation assets could submit a net bid of 20MW into the DAM or IDM. 2.2.8 The market participant is free to divide its bids into smaller parcels if it wishes, including bids linked to specific generating units. Portfolio bidding therefore provides greater flexibility to market participants in terms of the preferred bidding strategy. 2.2.9 This means that it enables some market participants to better optimise their own assets while accounting for more complex factors that may not be capable of being captured in a centralised algorithm. This would be of most benefit to portfolio players, rather than small independent generators or suppliers (with no more than one generating unit). 2.2.10 In addition, portfolio bidding opens up the market for financial market players, which might stimulate liquidity in the market. There might also be more scope for aggregators who could create a larger portfolio. However, it is also possible to allow aggregation within a unit-based bidding regime (e.g. AGUs in the SEM), although there will be typically be limits on the scope of aggregation in those circumstances (e.g. total amount of aggregation allowed, or size of units that can be aggregated). 2.2.11 On the other hand, portfolio-based bids in the DAM and the IDM will not specify the details (including location) of generating units supporting these bids. This could reduce the transparency of the DAM and ID at the time of bidding and provision of market results. It may also make ex-post market monitoring activities more complicated, depending on the granularity of the portfolio bids (e.g. in terms of price-quantity pairs). 2.2.12 In all of the options presented in this paper, it is assumed that market participants are required to provide unit-based physical nominations2 to the TSO after they have received their schedule from the DAM (or IDM). This is intended to provide the TSO with more information (including location) on the expected production schedule (and any possible resulting feasibility issues). 2 The nomination process is where the market participant will, based on its portfolio schedule from the market, send the detailed unit based information to the TSO on how he plans to honour its schedule (and balance responsibility). Gross portfolio bidding: 2.2.13 Gross portfolio bidding is normally applied to increase transparency for all volumes submitted to the market and can be seen as a mitigation measure for the lack of transparency for portfolio bids. 2.2.14 Under gross portfolio bidding, a market participant is required to provide separate bids for generation and demand into the DAM or IDM. Therefore, this does not allow netting of generation and demand by market participants. Using the example from 2.2.7, a market participant with 100MW of demand and 120MW of generation assets would submit two separate bids of 100MW demand and 120MW generation into the DAM or IDM. 2.2.15 The advantage of Gross Portfolio bidding is that it should encourage more liquidity in the DAM and IDM, helping to develop liquidity ‘along the curve’ and providing an effective near time market for participants to balance their positions and avoid exposure to the imbalance prices3. 3 See Ofgem ‘Secure and Promote’ consultation and responses from stakeholders on this issue. GB vertically integrated players have entered into gross bidding agreements for 30% of volumes. Nord Pool Spot also has gross bidding agreements which may go further to increasing transparency. Unit bidding: 2.2.16 Under unit bidding arrangements, a market participant has to submit a separate bid for each of its generating units that it wishes to participate in the market. Unit bidding is not applicable to the buyers of electricity, as demand is typically always allowed be represented by a portfolio bid (covering demand only). Therefore, when any reference is made to unit bidding hereafter, this should be interpreted as applying to bids to sell energy only. 2.2.17 A market participant representing both generation and load will therefore have to submit individual bids for each generating asset as well a single bid for the demand they are procuring energy to meet. 2.2.18 Unit bidding allows for more sophisticated bid formats as well as revealing the location of each accepted generating unit at an earlier stage (as the market schedule is forwarded to the TSO at the same time as to the market participant) compared to a portfolio bid where the detailed location will follow as part of the nomination process. As such it provides greater transparency at the time of bidding and provision of market results to market participants. Unit-based bidding may also make ex-post market monitoring easier for the Regulatory Authorities as they have specific unit-based bids to consider (rather than a set of price-quantity pairs for portfolio bids, which may or may not be able to be linked to specific units in ex-post market monitoring). 2.2.19 Unit bidding means that the optimization across production assets in a portfolio is carried out by the central algorithm taking into account the bids and offers received from all available generating units and demand. This restricts the ability of each market participant to optimise within its portfolio (to that extent it is unable to accurately reflect the commercial and technical operating characteristics of its plant within the permitted bids/offer structure). It may also be a barrier to financial market participants from participating in the market. 2.2.20 The impact of unit-based bidding on the scope of aggregation will depend on the particular rules in place – for example, the current SEM market requires unit based bidding for the majority of generator units but allows for portfolio based bidding from aggregated generator units and demand side units. 2.2.21 To conclude, the choice of unit or portfolio bidding will depend on balancing the potential efficiency gains by allowing market participants the freedom to manage the trading of their own portfolio on an aggregate basis with the advantages of unit bidding in terms of earlier transparency of market data that is specific to generation units (including location) and easier market monitoring. MANDATORY VS. VOLUNTARY (DAM) 2.2.22 Mandatory participation in a market means the following for different types of market participants: o Thermal generating units have to submit bids for their expected availability o RES have to submit bids based on forecasted output for intermittent RES and based on availability for controllable RES or with absolute priority dispatch submit an expected output o Demand has to submit bids for the forecasted demand level 2.2.23 In the case where bids are regulated (for example if SRMC bidding regulation is in place) this limits further the ability of market participants to choose the desired market for trading. In the case where there are no bidding rules then market participants have the flexibility to submit bids that would place them out of merit or conversely to ensure that that are ‘must run’ through submitting zero or negative prices. This will be a vital part of a risk management, but will also impact on overall market results. 2.2.24 The reason for making a market mandatory is normally to pool liquidity in at least one time-frame, to deliver a robust and transparent reference price. Mandatory participation can also provide a level playing field for markets with potential market power issues and ensure that independent suppliers can easily access electricity on nondiscriminatory terms. 2.2.25 However, arguments can be made that making a market mandatory limits the ability of market participants to tailor their risk management strategy by choosing the preferred timeframes for energy trading adjusted to the individual market participants´ preferences. 2.2.26 The obvious flipside of allowing market participants choice over where to trade is whether there may be low liquidity4 in the individual market timeframes. Liquidity is usually defined as the degree to which an asset can be bought or sold in the market without affecting the asset's price. Therefore, low liquidity can mean that the reference price from the market is less representative of the value of the underlying commodity. This is a major concern where the market is not fully competitive and places risks on non vertically integrated players by removing their tools for risk mitigation (as discussed in the SEM Committee Next Steps Paper). There is therefore a balance to be struck between the risk management and liquidity/reference price issues. 4 EXCLUSIVE VS. NON-EXCLUSIVE (IDM) 2.2.27 This refers to whether the (organised) IDM is the only way for a market participant to be able to change their nominated position after the DAM and ahead of the final intraday gate closure. The IDM can be exclusive or non-exclusive. 2.2.28 Were the IDM to be non-exclusive, then market participants would then have the flexibility to balance their position within their own portfolio, or through unrestricted bilateral trading with other market participants in the same bidding zone outside the continuous European market coupling arrangements. 2.2.29 On the other hand, if the centrally organised IDM is exclusive this is the only place where market participants can refine their position intraday. 2.2.30 Similar arguments regarding the compulsory nature of the market apply to the IDM as to the DA. DA liquidity is important for providing a robust reference price against which forward financial contracts may be struck. Liquidity is necessary for the IDM to allow market participants to adjust their positions form the DA ahead of the balancing timeframe. BID FORMAT (DAM) 2.2.31 The Price Coupling of Regions algorithm, EUPHEMIA, accepts a set of different bids with different degrees of complexity. However, it cannot currently accommodate complex three-part bid structures like those used in the current SEM market arrangements. The alternative bid structures that are considered in the HLD options presented in this document are the following: Simple bid: A simple price-quantity bid (ie. 50MW for the price of 40€/MWh for a single market settlement period). One bid can consist of a set of these price-quantity pairs in a monotonously increasingly order to reflect the individual prices for the assets that form a portfolio. Block bid: A bid that refers to more than one market settlement period, potentially with variable output over different periods and has to be accepted as a whole. Block bids can also be linked with a bid being considered conditionally if another bid (that it is linked to) is accepted. Sophisticated bid5: A set of simple hourly bids belonging to a single market participant with additional complex conditions. These conditions include the following: 5 These refer to generating units rather than the demand-side or a portfolio bid that could include more than one generating unit o Minimum income condition (MIC) . The amount of money collected over the market settlement periods covered by the set of bids must cover production costs, which are defined by a fixed term (in €) and a variable term (in €/MWh). MIC orders are either activated or deactivated as a whole. o Load gradient . The amount of energy matched in one period is limited by the amount of energy matched in the previous period. The load gradient condition is equivalent to a generating unit specifying a ramp rate. o Scheduled stop . In the case where a market participant has submitted a MIC bid for a power plant that is not accepted, a Scheduled Stop bid allows for accepting a subset of the bids (e.g. up to 3 hours) to allow for a non- abrupt shut-down of the power plant. The above conditions can be used in separation or be combined. Complex bids: Three part bids that include variable cost of generation, start-up costs, no- load costs as well as other technical characteristics (ramp rates etc.). Such bids are used in the current SEM market arrangements. 2.2.32 Portfolio bidding can be accommodated though simple or block bids. Unit bidding allows for the whole range of bids (simple, block, sophisticated and complex). 2.2.33 Further information on the bidding structures catered for in the EU DA market can be found in the two information publications from SEMO6. 6 http://www.eirgrid.com/media/PCR_EUPHEMIA_CLARIFICATION.pdf http://www.eirgrid.com/media/PCR_NWE_MO_TSO_Review.pdf BID FORMAT (IDM) 2.2.34 A periodic auction can allow a more sophisticated set of bids and offers than continuous trading, where only simple and block bids are allowed. 2.2.35 The current draft version of the CACM NC states that intraday trading shall be continuous with congestion pricing. However, there are provisions for additional periodic auctions that have to complement continuous trading. All options presented in this paper can support both forms of trading (only continuous, or continuous accompanied by periodic auctions). 2.2.36 If periodic auctions are to be implemented, this might allow for more sophisticated bids and the nomination process will be similar to the process in the DAM. In terms of practicality, given that the time for running an intraday auction would be limited in comparison to the DAM auction, the degree of sophistication of the bid might be reduced in intraday markets, even with periodic auctions. 2.3 PROCESS FOR REACHING FEASIBLE DISPATCH POSITION 2.3.1 This topic covers the interaction of the electricity market with the activities of the TSO, who is ultimately responsible for the safe and secure operation of the electricity system. 2.3.2 Under this topic we consider the starting point of the TSO’s scheduling and dispatch activities and how market participants can provide commercial information to support the TSO in ensuring a balance between supply and demand and a stable frequency. 2.3.3 The main issues for reaching a feasible dispatch position are: o Starting point of dispatch and the time at which its made available to the TSO o Bids to the TSO for balancing purposes o Timing of submitted bids STARTING POINT OF DISPATCH 2.3.4 In all the HLD options, the TSO is ultimately responsible for the safe and secure operation if the network (including respecting conditions such as absolute priority dispatch where it exists). This may require the TSO to take actions in parallel with the operation of the traded energy markets (e.g. forward, DAM, IDM). 2.3.5 There are two broad choices for the starting point that the TSO can use for reaching a feasible dispatch position. 2.3.6 The first approach is that the TSO’s starting point for dispatch is the nominations provided by market participants based on settled trades (including in the DAM and IDM). In this case, the TSO’s objective is to reach feasible dispatch by minimising the cost of deviation from the market participants’ nominations based on bids and offers (incremental and decremental) into a balancing mechanism for residual volumes. 2.3.7 A key aspect of this is the time at which the TSO receives all nominations from participants where they can in turn satisfy themselves that an achievable dispatch is possible. Market participants will provide initial nominations to the TSO after the DA market, and will update nominations at various points during the ID timeframe. There are different ways in which the TSO can act on the updated nominations – e.g. on a continuous basis or periodically. 2.3.8 The second approach is that the TSO issues dispatch instructions to minimise overall production cost based on commercial and technical data submitted by the market participants into a pool-based scheduling and dispatch process at fixed points during D-1 and D. Even in this case the flows across the interconnectors arising from the DA and ID markets have to be respected. The key question for this approach is how the pool-based scheduling process affects the incentives on market participants to trade in the non-pool pan European markets (e.g. DAM and IDM). BIDS TO THE TSO FOR BALANCING AND DISPATCH 2.3.9 In all the HLD options, market participants have to submit detailed technical information to the TSO to help it operate the system safely and securely. The main differentiating factor is the form of the commercial information with two alternatives available: o Complex bids for use in an Integrated Scheduling Process designed to produce unit commitment. An additional economic dispatch tool may need to be used for energy balancing closer to real time. o Simple incremental and decremental bids (incs and decs) for use in a separate Balancing Mechanism that produces an economic merit order. 2.3.10 The Integrated Scheduling Process is defined in the Electricity Balancing Network Code as follows: “Integrated Scheduling Process means a market-based continual process performed by a Transmission System Operator operating a Central Dispatch System in order to ensure secure system operation in real time. It starts in day- ahead timeframe and last until real-time. It is implemented as an optimisation problem where Balancing, congestion management and Balancing Capacity procurement are performed simultaneously based on bids and offers as well as technical parameters provided by Market Participants. Integrated Scheduling Process determines the Unit Commitment of the majority of system resources capacity. The objective function for the Integrated Scheduling Process is minimisation of energy delivery cost while complying with operational security requirements.” 2.3.11 In both cases however all commercial data would relate to individual units. In the case where the bids are simple price/quantity incs and decs, the TSO still have the technical characteristics of each individual unit as submitted by the unit operator. 2.3.12 In an Integrated Scheduling Process complex bids are used to better reflect the cost structure of the generating units, whereas in the separate Balancing Mechanism simple incs and decs in the form of commercial information available to the TSO. 2.3.13 The working assumption in either case is that marginal prices (i.e. pay as cleared) will be used to settle bids and offers activated by the TSO for the purpose of balancing energy. In the pool, these marginal prices will simply be the half-hourly ex-post system marginal costs calculated in the pool. 2.3.14 In the case where a separate balancing mechanism is in place, the TSO will need to calculate marginal prices for the activation of balancing energy. Where the TSO also uses the bids and offers in the balancing mechanism to resolve non-energy balancing issues, then it will need to put in place mechanisms to isolate the costs of energy balancing actions. For example, this could be done through the ‘flagging and tagging’ of non-energy balancing actions so that they are not included in the calculation of balancing prices, or through the calculation of an ex-post unconstrained schedule for the balancing bids and offers only. This tagging process is carried out in other European markets. Another option would be to have separate markets for redispatch and for balancing. 2.3.15 Where bids and offers for energy balancing are used by the TSO for non-energy balancing purposes (e.g. to relieve a network constraint), the assumption is that these would be settled on a pay as bid process. 2.4 IMBALANCE 2.4.1 Ultimately, market participants will pay/receive an ex-post price for all volumes not settled in ex-ante markets e.g. intraday, day-ahead and forward, or activated by the TSO. This means that the nature of the ex-post arrangements is very important and will affect the incentive for market participants to trade volumes in earlier markets. Given that the imbalance market is in essence the market of last resort its structure is fundamental to the design of the overall electricity trading arrangements. 2.4.2 These ex-post prices could be determined through the operation of pool arrangements (which inform the schedule and dispatch) or by the marginal cost of pure energy balancing actions taken by the TSO in a specific energy balancing mechanism (either alongside or after the intraday market). Pool arrangements 2.4.3 Typically, pool arrangements will calculate (marginal) ex-post (or imbalance) prices through an unconstrained market schedule based on complex bids submitted by market participants (as in the SEM today). The ex-post price calculations will need to include an element to allow market participants to recover start-up and no-load- costs, which could be for example the uplift mechanism used in the SEM today or alternatively more targetted make-whole payments. Separate balancing mechanism 2.4.4 In calculating the imbalance or ex-post price, the TSO will need to put in place mechanisms to isolate the costs of energy balancing actions as set out in section 2.3.12. The marginal price(s) from this will be used to determine the imbalance price. 2.5 ARRANGEMENTS FOR LONG-TERM TRADING 2.5.1 This topic covers the arrangements for trading in the forward timeframe (before the DA stage) and can be considered separately from the trading of energy within a bidding zone (internal), and between bidding zones (which requires access to cross- zonal capacity). INTERNAL 2.5.2 Forward trading can be physical or financial. 2.5.3 Physical forward trading means trading of physical contracts for delivery and consumption of electricity ahead of the DAM. Trading can be exchange-based, carried out via a broker or purely a bilateral trade directly between market participants. 2.5.4 If exchange-based then all financial settlements are carried out by a central Clearing House. The market participants have to nominate their volumes from the physical forward trading as part of the DA nominations to the TSO. 2.5.5 All four HLD options presented in this paper would allow the establishment of a financial market. Financial forward trading means trading of financial products ahead of the DAM. The main purpose of such any forward market is to give market participants the opportunity to have a long-term hedge against price risk in the short-term physical markets (e.g. DAM, IDM or ex-post). The reference price for the contract is therefore taken from the relevant short-term physical market. 2.5.6 The Financial market and the Physical underlying market (in most cases the DAM) are dependent on each other to support liquidity. 2.5.7 To have a liquid Financial market, the robustness and liquidity of the reference price is important, and one of the key aspects to this is to have high share of the underlying volumes to be priced as part of this. Without a robust and reliable reference price the development of financial markets will be much more difficult. 2.5.8 At the same time, for a market participant to put most of its volumes in a (voluntary) short-term market (day-ahead), it needs a liquid tool to hedge its price risk (although the forward market does not necessarily protect against volume risk as it doesn’t lock in physical volumes). 2.5.9 The financial market can have forward, futures, options and CfD products for long term risk hedging, with the particular nature of these products being driven by the preferences of market participants. Typically the products will be yearly (multiple years), quarterly, monthly, weekly and potentially even down to daily. Each of these products will have their individual trading and delivery periods and it should also involve cascading between timeframes (open contracts in yearly contracts are automatically transferred to 4 quarterly products after closure of the yearly contract and so on). 2.5.10 A centralised financial market will require centralised Clearing House arrangements that will manage settlement, invoicing and collaterals. The market participants will receive separate settlement statements and invoices from the Clearing House thus this will not be part of any energy market settlement. This will not affect any nominations or processes in the energy markets. 2.5.11 Another solution is where financial trading is carried out through brokers. Tullett Prebaun provides such services for CfDs in the current SEM. CROSS-BORDER 2.5.12 The existence of long-term cross-border risk hedging tools is a central feature of the Target Model. These tools can be in the form of explicit physical access to cross- zonal capacity before the DAM (where all physical capacity is allocated implicit), or financial products. 2.5.13 Physical explicit rights can be provided through a Physical Transmission Right (PTR) allocated through auctions organised by the owner of the cross-zonal capacity. A PTR gives the holder the right to physically nominate a flow on the interconnector before the DA stage. Under the Target Model, ‘Use it or sell it’ (UIOSI) provisions are applied to PTRs at the DA stage. This means that if a flow has not been nominated by the DA stage, the capacity is made available for implicit allocation through the DAM (and then into the IDM if unsold in the DAM). The PTR holder receives the implicit value of the capacity in the DAM (down to a minimum value of zero) i.e. this value is the price difference between the two zones connected by the cross-zonal capacity covered by the PTR (in the direction of flow allowed by the PTR). 2.5.14 PTRs allow market participants to directly hedge the price and volume risk associated with forward cross-border energy trades. However, PTRs can reduce the amount of physical cross-zonal capacity available for implicit allocation in the DAM (and then the IDM), which may reduce the effective liquidity of the DAM. 2.5.15 Financial products can take two forms – a Financial Transmission Right (FTR), which is sold only by the cross-zonal capacity owner as in the case of PTRs (and hence is backed up by the congestion rents received through market coupling), or a CFD, which can be sold by any party. In the options, where we have assumed that only financial cross-border products are available, we have assumed that they are FTRs. 2.5.16 An FTR does not give the holder a right to physically nominate a flow at the DA stage. Instead they receive the price differential between the two zones for which they hold cross-zonal capacity. FTRs can either be options (in which case the payment to the FTR holder is never less than zero) or they can be obligations (whereby the FTR holder has to make a payment if the price differential is in the opposite direction to their capacity holding). 2.5.17 FTRs allow market participants to directly hedge the price risk associated with forward cross-border energy trades, without reducing the amount of physical capacity available to be used in market coupling. However, as with financial forward energy contracts, they rely on liquid DAMs being in place in order to allow the FTR holder to manage its volume risk (i.e. whether or not it will get scheduled). The type of cross border transmission products (FTRs or PTRs) thus depends largely on the liquidity (and hence the compulsory nature) of the DAM. 3 SUMMARY OF OPTIONS 3.1.1 This document presents four options for the HLD of energy trading arrangements: o Adapted Decentralised Market o Mandatory ex-post Pool for Net Volumes o Mandatory Centralised Market o Gross Pool – Net Settlement Market 3.1.2 Table 2 and Table 3 describe how each option addresses the topics discussed in Section 2. Table 2 has been colour-coded to visually describe how the options range from market arrangements where market participants have both greater responsibilities and risk mitigation opportunities (coloured in blue), to ones in which there is much greater central control of market participants activities (coloured in orange). Table 3 spells out in more detail how each option is built up through the choices for each topic (and uses the same colour-coding as Table 2). 3.1.3 The colour-coding in Table 2 illustrates the difference in the ‘philosophies’ underpinning the options: o The Adapted Decentralised Market option is characterised by an emphasis on allowing market participants more choice over the markets and timeframes in which they trade energy in order to manage risk. This translates into this options being coloured in blue across all topics in Table 2. o The Mandatory ex-post Pool for Net Volumes is characterised by some choice for market participants around their trading in the day-ahead and intraday timeframes (in the top few rows), but ultimately, relies on more centralised approach to the determination of dispatch and ex-post prices and volumes (e.g. through complex bidding into an integrated scheduling and dispatch process to help the TSO reach a least-cost dispatch). This results in this option being coloured blue for day-ahead and intraday markets but orange for the actions taken by the TSO and ex-post pricing and scheduling arrangements in Table 2. o The Mandatory Centralised Market emphasises the importance of the Day- Ahead Market (and then the European Intraday Market) as the main market for physical trading of energy between market participants. This translates into orange colouring in the topics covering the DA and ID energy trading arrangements, and blue shades dominating in the topics covering TSO actions and imbalance arrangements in Table 2. o The Gross Pool – Net Settlement Market is characterised by more choice for market participants around their trading in the day-ahead and intraday timeframes (in the top few rows), but ultimately, relies on a highly centralised approach to the determination of dispatch and ex-post prices and volumes (e.g. through complex bidding into an integrated scheduling and dispatch process to help the TSO reach a least-cost dispatch). This results in this option being coloured blue for day-ahead and intraday markets but dark orange for the actions taken by the TSO and ex-post pricing and scheduling arrangements in Table 2. DecentralisedCentralisedVoluntaryMandatoryPortfolioUnitSimple bidsComplex bids Table 2 – ‘Philosophy’ of options Adapted Decentralised Market Mandatory ex-post Pool for Net Volumes Mandatory Centralised Market Gross Pool - Net Settlement Market Participation in European markets for trading of energy in DA and ID timescales DA Portfolio vs. unit bidding Mandatory vs. voluntary Bid format ID Portfolio vs. unit bidding Exclusive vs. Non-exclusive Bid format Process for reaching feasible dispatch position Starting point of dispatch Bids to the TSO for balancing and dispatch Timing of bid submission Imbalance/Pool settlement Arrangements for long- term trading Internal Cross-border Table 3 – Overview of options Adapted Decentralised Market Mandatory ex-post Pool for Net Volumes Mandatory Centralised Market Gross Pool - Net Settlement Market Participation in European markets for trading of energy in DA and ID timescales DA Portfolio vs. unit bidding Gross portfolio bidding Net portfolio bidding Unit bidding Net portfolio bidding Mandatory vs. voluntary Voluntary participation [plus specific liquidity promoting measures] Voluntary participation [with volume limitation measures] Mandatory participation Voluntary participation Bid format Simple, block (or sophisticated unit) bids Simple, block (or sophisticated unit) bids Simple, block or sophisticated bids Simple, block (or sophisticated unit) bids ID Portfolio vs. unit bidding Gross portfolio bidding Unit bidding Unit bidding Unit bidding Exclusive vs. Non- exclusive Non-exclusive Non-exclusive [with same volume limitation measures] Exclusive Non-exclusive Bid format Simple, block [or sophisticated] bids Simple, block [or sophisticated] bids Simple, block [or sophisticated] bids Simple, block [or sophisticated] bids Process for reaching feasible dispatch position Starting point of dispatch - DA nomination is the starting point (updated in the IDM) - Maintaining absolute priority dispatch - DA nomination is the starting point (updated in the IDM) - Maintaining absolute priority dispatch - DA nomination is the starting point (updated in the IDM) - Maintaining absolute priority dispatch - IC volumes determined by DAM and IDM - Maintaining absolute priority dispatch Bids to the TSO for baancing and dispatch Voluntary inc's and dec's up to IDM GC (mandatory inc's and dec's for generating units after IDM GC) Mandatory net (+/-) complex bids for generating units Mandatory inc's and dec's for generating units Mandatory complex bids for generating units Timing of bid submission At DA and then updated continuously At DA and then updated continuously At DA and then updated continuously At DA and then updated at specific windows Imbalance/Pool settlement Marginal imbalance price applied to all market participants based on (+/-) energy balancing actions Net ex-post unconstrained market schedule to minimise production cost that determines the ex-post prices paid to/by all market participants (prices may vary by direction) Marginal imbalance price applied to all market participants based on (+/-) energy balancing actions Full ex-post unconstrained market schedule to minimise production cost that results in a single marginal price paid for all scheduled volumes Arrangements for long-term trading Internal Both physical and financial trading Both physical [with volume limitation measures] and financial trading Financial trading Financial trading Cross-border PTRs to support bids for interconnector capacity PTRs to support bids for interconnector capacity FTRs to support bids for interconnector capacity FTRs to support bids for interconnector capacity 4 OPTION 1: ADAPTED DECENTRALISED MARKET 4.1.1 Of all the options, this one provides market participants greater choice over the markets and timeframes in which they trade energy in order to manage risk. However, increased trading opportunities for a market participant come with a greater responsibility for following its nominated position. 4.1.2 All forward, DA and ID trading is portfolio-based, although market participants have the discretion to submit unit bids into the DAM and IDM. This means that market participants have more freedom for optimising within their own portfolio of production assets (compared to all of these options). This may allow market participants to take account of information about commercial and technical characteristics where it is not possible to capture in the bid formats and structure that may be allowed in a centralised scheduling and dispatch algorithm. 4.1.3 One of the main issues for this type of market arrangements is the markets and timeframes where the most liquid trading happens. Therefore, this option contains specific measures in place to encourage liquidity in the DAM as a key trading forum under the Target Model. These include market-maker obligations on some or all participants and gross portfolio bidding. 4.1.4 We now describe how this option operates from the forward timescales onwards. Figure 1 summarises the timing and direction of flows of information between the different stakeholders in the Irish electricity market under the Adapted Decentralised Market option. 4.1.5 In the forward timeframe, market participants can trade both physical energy and financial products through an intermediate agent (e.g., a broker or a power exchange), or directly with another market participants. A well functioning financial derivatives market (futures and forwards) allows for price hedging whilst mitigating the risk of market participants not trading physical volumes in the DAM and not promoting liquidity in the short-term physical markets. 4.1.6 Physical Transmission Rights (‘PTRs’) with UIOSI provisions at the DA Stage are in place to support physical long-term cross-border trading. 4.1.7 All bids into the DAM are submitted to the NEMO (the market operator under the European market coupling arrangements). The NEMO in its turn transfers exactly the same bid (in an anonymised form) to the PCR algorithm (Euphemia). This returns the DAM price (as a firm ex-ante price), and the volumes and interconnector flows to be settled at that price. The results are provided to market participants on a portfolio basis where portfolio bids were submitted, and a unit basis where unit bids were submitted. 4.1.8 Market participants in their turn nominate the units and the corresponding output level of each one that will be used for respecting their individual DAM (portfolio) schedule as well as the results of any physical forward trading to the TSO. This would be done by the early evening of D-1 (for a trading day starting at 23.00 UTC). Nominated volumes (traded up to and including DAM) are the starting point of the dispatch process. 4.1.9 The TSO is responsible for ensuring a feasible dispatch schedule (based on minimising costs of deviating from the nominated position). It takes relevant actions and issues dispatch instructions for ensuring system security whilst respecting absolute priority dispatch (as defined in SEM-11-062). The TSO can take balancing actions or even re-commit plants upon receiving DA nominations from market participants. There may be instances where the TSO need to take actions before nominations are received given the start-up times of some plants. 4.1.10 Market participants are responsible for updating their nominated positions to the TSO to reflect changes intraday, which could result from inter alia: o Matching of bids and offers in the European intraday market; o Rebalancing within their own portfolio (e.g. to balance change in plant availability or updated wind forecast); o Unrestricted bilateral trading with other market participant within SEM (i.e., outside of the continuous matching algorithm). 4.1.11 Intraday trading through the European market coupling arrangements is done on a continuous basis, although periodic intraday auctions could be accommodated. Market participants can start trading in the IDM upon nominating DAM volumes. When trading continuously market participants submit simple unit bids to the IDM or whatever bids can be accommodated by the European Market arrangements. 4.1.12 If periodic auctions are to be implemented, this might allow for more sophisticated bids and the nomination process will be similar to the nomination process at the DA stage. 4.1.13 Depending on the intraday nominations and as other information becomes available (plant availability, updated intermittent generation forecast etc.), the TSO can, if required, issue updated dispatch instructions (even before the ID gate closure). 4.1.14 These dispatch instructions can use the bids and offers submitted by market participants into the separate balancing mechanism operated by the TSO. These bids can be submitted at any time after the DA stage and be updated up to the ID GC. In some markets the TSO can have longer term bilateral contracts in place with balancing service providers. This separate balancing mechanism will need to accommodate at least one of the Standard Products defined for the activation of balancing energy at a European level. This balancing mechanism is one of the tools that the TSO has to ensure secure system operation as well as energy balance at all times. 4.1.15 Participation in this balancing mechanism is voluntary up to the gate closure of the intraday market but mandatory after the intraday gate closure. Bids and offers take the form of simple incremental and decremental bids and offers (incs and decs) from market participants, which can be updated on a continual basis (at least up to intraday gate closure). Bids and offers accepted by the TSO for energy balancing purposes in each period are settled ex-post at the price of the marginal energy balancing action activated by the TSO in each trading period (i.e., each half hour). 4.1.16 All market participants are balance responsible although they can nominate a Balance responsible Party to act on their behalf. This means that all volumes not settled through the energy market (or activated by the TSO) are settled at an imbalance price in each period. This imbalance price is set at the price of the marginal energy balancing action activated by the TSO in each period. TSOMCOMarket participantsDAM OpeningForwardNEMO/PXDay-Ahead marketPCR algorithmExchange- based physical tradingDay-AheadDAM Gate ClosureDA nominationsDispatch processCongestion managementBalancingActivation of balancing servicesIntradayAfter the dayIDM & BM Gate ClosureReal timeIntraday shared order bookIntraday marketTradesBidsPrice & schedule by portfolioAggregated bid curvePrice & IC scheduleDA nominations by unitReserve procurementBidsBidsMatched bidsBidsMatched bidsID nominationImbalance settlementVolumes from FW, DA, ID and BM and metered volumesImbalanceExchange- based financial tradingTradesDispatch instructionsID nominationBalancing marketDispatch instructionsPortfolio to unitDispatch instructionsVoluntaryMandatoryConditionalComplex bidLegend Figure 1 – Timing and direction of information flows in Adapted Decentralised Market option 5 OPTION 2: MANDATORY EX-POST POOL FOR NET VOLUMES 5.1.1 This option is characterised by a pool-based approach to the determination of dispatch and ex-post prices and volumes (e.g. through complex bidding into an integrated scheduling and dispatch process to help the TSO reach a least-cost dispatch). There is some choice for market participants around their trading in the day-ahead and intraday timeframes (in the top few rows), although this is up to a ‘regulated’ limit on the level of trading (which is expected to be more limited than say in the Adapted Decentralised Market). 5.1.2 Under this option, market participants can make firm ex-ante trades (in forward, DA and ID timescales), up to a certain volume. These trades are then used to support unit-based nominations from market participants to the TSO as the starting point for its dispatch process. The dispatch process is integrated with an ex-post pool based on complex bids submitted by all generating units. This means that where a volume has been nominated for a generating unit, the complex bid should include a shut- down cost. 5.1.3 Therefore, this option offers a choice to market participants of whether to trade physically in the ex-ante markets (up to a certain volume) and/or an ex-post pool. 5.1.4 All forward, DA and ID trading is portfolio-based, although market participants’ have the discretion to submit unit-based bids into the DAM and IDM. All generating unit bids into the pool (for the ex-post schedule and dispatch) are unit-based. 5.1.5 We now describe how this option operates from the forward timescales onwards. Figure 2 summarises the timing and direction of flows of information between the different stakeholders in the SEM under the Mandatory Ex-post Pool for Net Volumes option. 5.1.6 In the forward timeframe, market participants can trade both physical energy and financial products through an intermediate agent (e.g., broker or power exchange), or directly with another market participants. A robust financial derivatives market (futures and forwards) allows for price hedging whilst mitigating the risk of market participants not trading physical volumes in the DAM and promoting liquidity in the short-term physical markets. 5.1.7 Physical Transmission Rights (‘PTRs’) with UIOSI provisions at the DA Stage are used for supporting long-term cross-border trading. 5.1.8 All bids into the voluntary DAM are submitted to the NEMO (the market operator under the European market coupling arrangements). The NEMO in its turn transfers the same bid in an anonymized form to the PCR algorithm (Euphemia). This returns the DAM price (as a firm ex-ante price), and the volumes and interconnector flows to be settled at that price. The results are provided to market participants on a portfolio basis where portfolio bids were submitted, and a unit basis where unit bids were submitted. 5.1.9 Market participants in their turn nominate the units and the corresponding output level of each one that will be used for respecting their individual DAM (portfolio) schedule to the TSO. This would be done by the early evening of D-1 (for a trading starting at 23.00 UTC). Nominated volumes (traded up to and including DAM) are the starting point of the dispatch process. 5.1.10 The TSO is responsible for ensuring a feasible dispatch (based on minimising costs of deviating from the nominated positions) accounting for the complex bids submitted by market participants, which can be updated during the day. For a generating unit with a nominated volume this means a complex bid with an associated shut-down cost (instead of a start-up cost). 5.1.11 The TSO takes relevant actions and issues dispatch instructions for ensuring system security whilst respecting absolute priority dispatch for RES. The TSO can take balancing actions or even re-commit plants upon receiving DA nominations from market participants. 5.1.12 Market participants are responsible for updating their nominated positions to the TSO to reflect changes intraday (up to the limit on total nominated volumes), which could result from inter alia: o Matching of bids and offers in the European intraday market; o Rebalancing within their own portfolio (e.g. to balance change in plant availability or updated wind forecast); o Direct trading with other market participant in Ireland outside of the continuous matching algorithm. 5.1.13 Intraday trading through the European market coupling arrangements is done on a continuous basis, although periodic intraday auctions could be accommodated. Market participants can start trading in the IDM upon nominating DAM volumes. When trading continuously market participants submit simple unit bids into the IDM. 5.1.14 Periodic intraday auctions could be accommodated within this approach. Indeed, updating dispatch instructions based on complex bids (up and down) is likely to require the TSO to run its optimization process in the pause in continuous intraday trading that has been proposed to support periodic intraday auctions. This pause is likely to be relatively short (say 15 minutes) which will limit the run-time and scope of the dispatch algorithm. 5.1.15 Depending on the intraday nominations and as other information becomes available (plant availability, updated intermittent generation forecast etc.), the TSO can potentially issue updated dispatch instructions based on the mandatory net complex bids submitted for the ex-post pool. 5.1.16 Cross-border balancing is based on the complex bids that are initially submitted and thereafter updated. These are translated by the TSO to Standard Products that can be used for trading balancing energy cross-border. 5.1.17 All volumes scheduled in the ex-post pool are settled at the ex-post prices determined by the pool. The use of net complex bids raises challenges for the calculation of a single ex-post price, because the calculation of uplift typically assumes that plants are all being scheduled upwards. TSOMCOMarket participantsDAM OpeningForwardNEMO/PXDay-Ahead marketPCR algorithmExchange- based physical tradingDay-AheadDAM Gate ClosureDA nominationsDispatch processCongestion managementBalancingActivation of balancing servicesIntradayAfter the dayIDM & BM Gate ClosureReal timeIntraday shared order bookIntraday marketTradesBidsPrice & schedule by portfolioAggregated bid curvePrice & IC scheduleDA nominations by unitReserve procurementBidsMatched bidsBidsMatched bidsID nominationExchange- based financial tradingTradesDispatch instructionsID nominationDispatch instructionsDispatch instructionsEx-post poolComplex bids for net volumesPrice & schedule for net volumesUpdated complex bids for net volumesPortfolio to unitVoluntaryMandatoryConditionalComplex bidLegend Figure 2 - Timing and direction of information flows in Mandatory ex-post Pool for Net Volumes option 6 OPTION 3: MANDATORY CENTRALISED MARKET 6.1.1 This option emphasises the significance of the DAM as the main market for ex-ante physical trading by mandating participation in this market to provide a strong DAM price and a DAM schedule that forms a good starting point for a feasible initial dispatch. The reliance on sophisticated unit-based bids into the DAM is designed to help the results of the DAM to reflect (some) technical plant constraints as well as helping market participants to manage the risks around start-up and no-load costs. 6.1.2 We now describe how this option operates from the forward timescales onwards. Figure 3 summarises the timing and direction of flows of information between the different stakeholders in the Irish electricity market under the Mandatory Centralised Market option. 6.1.3 In order to encourage liquidity in the day-ahead market, no physical trading is allowed in the forward timeframe, though participants would be free to trade financial contracts. A variant of this option would allow for physical trading in the forward timeframe up to a certain regulated market share, thus making the DAM pseudo-mandatory where all volumes that have not been sold/bought in the forward timeframe having to be submitted in the DAM. 6.1.4 Financial Transmission Rights (‘FTRs’) are used to allow market participants to hedge price risk associated with financial forward trading across bidding zones. 6.1.5 Mandatory participation in the DAM means the following for different types of market participants: o Thermal generating units have to submit bids for their expected availability o RES have to submit bids based on forecasted output for intermittent RES and based on availability for controllable RES or with absolute priority dispatch submit an expected output o Demand has to submit bids for the forecasted demand level 6.1.6 Trading in the DAM is unit-based and allows for sophisticated bids. All bids, including bids by the demand side, are submitted to the NEMO (the market operator under the European market coupling arrangements). The NEMO in its turn transfers exactly the same bid in an anonymised form to the PCR algorithm (Euphemia). This returns the DAM price (as a firm ex-ante price) and the volumes and interconnector flows to be settled at that price. 6.1.7 The scheduled production volumes are notified to market participants on a unit basis, which means that the schedule from the European DAM can be passed directly to the TSO to effectively act as the nominations for the starting point of the dispatch process. 6.1.8 The TSO is responsible for ensuring a feasible dispatch (based on minimising costs of deviating from the results of the DAM and IDM). Initial dispatch instructions are based on the technical plant information and the same bids submitted in the DAM, which include demand-side bids. This means that the balancing mechanism is based on mandatory participation from the DA stage onwards (on the basis of ‘technical availability’ and subject to a deminimis level). 6.1.9 The TSO assesses the feasibility of the market schedule, takes relevant actions if necessary and issues dispatch instructions for ensuring system security, and respecting absolute priority dispatch As all in the options, the TSO takes into account its own forecasts for generation availability (including renewables) and demand in issuing this dispatch instructions. 6.1.10 Market participants are responsible for updating their nominated positions to the TSO to reflect changes intraday. These changes to nomination can only result from the matching of (unit-based) bids and offers in the European intraday market as that is the only (exclusive) route to changing intraday nominations in this option. 6.1.11 Intraday trading through the European market coupling arrangements is done on a continuous basis, although periodic intraday auctions could be accommodated. Market participants can start trading in the IDM upon nominating DAM volumes. When trading continuously market participants submit simple unit bids. 6.1.12 If periodic auctions are to be implemented, this might allow for more sophisticated unit-based bids to be used (with the results of the IDM feeding directly into changes into market participants nominated volumes to the TSO). 6.1.13 Depending on the intraday nominations and as other information becomes available to the TSO (plant availability, updated intermittent generation forecast etc.), the TSO can, if required, issue updated dispatch instructions (even before the ID gate closure). 6.1.14 These dispatch instructions can use the bids and offers submitted by market participants into the separate mandatory balancing mechanism operated by the TSO in parallel with the intraday market. The balancing mechanism is mandatory up to technical availability (e.g. suppliers only have to submit volumes to be called in the balancing mechanism where the demand can actually be flexible). 6.1.15 This separate balancing mechanism will need to accommodate at least one of the Standard Products defined for the activation of balancing energy at a European level. This balancing mechanism is one of the tools that the TSO has to ensure secure system operation as well as energy balance at all times. 6.1.16 Bids and offers into the balancing mechanism take the form of simple incremental and decremental bids and offers (incs and decs) from market participants, which can be updated on a continual basis (at least up to intraday gate closure). Bids and offers accepted by the TSO for energy balancing purposes in each period are settled ex-post at the price of the marginal energy balancing action activated by the TSO in each period. 6.1.17 All market participants are balance responsible. This means that all volumes not settled through the energy market (forwards, DAM and IDM) are settled at an imbalance price in each trading period. This imbalance price is set at the price of the marginal energy balancing action activated by the TSO in each period. TSOMCOMarket participantsDAM OpeningForwardNEMO/PXDay-Ahead marketPCR algorithmDay-AheadDAM Gate ClosureDA nominationsDispatch processCongestion managementBalancingActivation of balancing servicesIntradayAfter the dayIDM & BM Gate ClosureReal timeIntraday shared order bookIntraday marketBidsPrice & schedule by unitAggregated bid curvePrice & IC scheduleDA nominations by unitReserve procurementBidsBidsMatched bidsBidsMatched bidsID nominationImbalance settlementVolumes from FW, DA, ID and BM and metered volumesImbalanceExchange- based financial tradingTradesDispatch instructionsID nominationBalancing marketDispatch instructionsDispatch instructionsVoluntaryMandatoryConditionalComplex bidLegend Figure 3 – Timing and direction of information flows in Mandatory Centralised Market option 7 OPTION 4: GROSS POOL – NET SETTLEMENT MARKET 7.1.1 This option relies on a centralised, pool-based approach to the determination of dispatch and ex-post prices and volumes (e.g. through complex bidding into an integrated scheduling and dispatch process to help the TSO reach a least-cost dispatch). 7.1.2 The centralised approach means that an ex-post pool based around complex bids becomes the ‘ultimate’ market with all market participants having to submit complex bids in order to produce an ex-post unconstrained schedule for the entirety of the market (subject to deminimis limits). 7.1.3 There is choice for market participants around voluntary financial trading in the day- ahead and intraday timeframes, but that trading has no direct impact on their physical positions within the Irish market (although it does affect the physical flows on the interconnector) – i.e. trading in the ex-ante markets does not affect nominations provided by individual market participants to the TSO, who schedules and dispatches the system to minimize the overall cost of production based on the bids and offers into the pool (respecting however, scheduled cross-border flows). 7.1.4 The results of the ex-ante markets do affect however the settlement in the ex-post pool. The ex-post price is only applied to volumes that are scheduled in the ex-post pool but have not been matched in the ex-ante markets. This is a net settlement process. 7.1.5 We now describe how this option operates from the forward timescales onwards. Figure 4 summarises the timing and direction of flows of information between the different stakeholders in the Irish electricity market under the Gross Pool – Net Settlement option. 7.1.6 This option has forward trading of financial products ahead of the DAM. The main purpose of such markets is to give market participants the opportunity to have a long-term hedge against price risk in the real-time markets (as reflected in the ex- post price). Financial Transmission Rights (‘FTRs’) are used to allow market participants to hedge price risk associated with financial forward cross-border trading (based on the reference price from the Day-Ahead market). 7.1.7 All (portfolio) bids into the voluntary DAM are submitted to the NEMO (the market operator under the European market coupling arrangements). The NEMO in its turn transfers exactly the same bid in an anonymized form to the PCR algorithm (Euphemia) that returns a DAM price and the IC schedule. 7.1.8 The resulting IC schedule is nominated directly to the TSO and acts as the starting point of the dispatch. Alongside the bids submitted to the DAM, market participants submit unit-based complex bids to NEMO, who runs the ex-post pool, and to the TSO. The TSO carries out an Integrated Scheduling Process based on those complex bids and other technical plant characteristics whilst respecting the IC schedule and issues initial dispatch instructions (which includes respecting absolute priority dispatch). Market participants can also submit updated complex bids to the TSO in relevant windows. 7.1.9 In the intraday timeframe market participants can trade financial contracts both continuously or participate in periodic auctions (if they exist) in order to refine their position. In the case where these financial trades result in a change in the IC schedule, an updated IC schedule is nominated to the TSO. 7.1.10 There is no separate balancing mechanism in place and all energy balancing actions taken by the TSO are based on the complex bids submitted initially at the DA stage and thereafter updated intraday. Cross-border balancing is based on translated (by the TSO) complex bids to Standard Products that can be used for trading balancing energy cross-border. 7.1.11 A full ex-post unconstrained pool (as per current arrangements) produces a single ex-post price. As this is a net settlement process, this price is applied to all volumes scheduled in the ex-post pool that have not been matched in the ex-ante markets. TSOMCOMarket participantsDAM OpeningForwardNEMO/PXDay-Ahead marketPCR algorithmDay-AheadDAM Gate ClosureDA nominationsDispatch processCongestion managementBalancingActivation of balancing servicesIntradayAfter the dayIDM & BM Gate ClosureReal timeIntraday shared order bookIntraday marketBidsPrice & IC scheduleAggregated bid curvePrice & IC scheduleReserve procurementBidsMatched bidsBidsMatched bidsID nominationExchange- based financial tradingTradesDispatch instructionsID nominationDispatch instructionsDispatch instructionsEx-post poolComplex bids from all unitsPrice & schedule for net volumesUpdated complex bids from all unitsVoluntaryMandatoryConditionalComplex bidLegend Figure 4 – Timing and direction of information flows in Gross Pool – Net Settlement Market option 8 CAPACITY REMUNERATION MECHANISMS 8.1.1 Capacity Remuneration Mechanisms (CRMs) are not presented as an integral part of any HLD option for the arrangements for the trading of energy within the SEM. This is because the design of a CRM (where it exists) should also take into account developments on capacity remuneration in neighbouring countries and European requirements (e.g. state aid guidelines, not distorting cross-border trade). 8.1.2 However, the Draft Decision on the HLD will present recommendations on for both the design of both energy and capacity markets (or lack thereof) as a package. Any CRM that is implemented under this new HLD will need to be justified under and meet the requirements of the EU State Rules for Energy. 8.1.3 When considering possible approaches for capacity remuneration mechanisms, there are two different aspects to consider: o Targeted intervention to address specific issues relating to capacity adequacy, with the supported capacity not participating in the energy trading arrangements – i.e. Strategic Operating Reserve. o Market-wide mechanisms for the recovery of capacity costs by resources participating in the energy trading arrangements. 8.2 Strategic Reserve 8.2.1 Strategic Reserve is usually implemented to address issues where specific types of capacity adequacy are not adequately rewarded through the energy trading arrangements. For example, this may relate to locational issues within a bidding zone, or where the ‘political’ requirement for security of supply is higher than can be supported by the economic signals from the energy trading arrangements. 8.2.2 There can be a variety of procurement processes used to create the Strategic Reserve (e.g. competitive tendering, regulated payments etc.), which will depend on the specific problem that has been identified. 8.2.3 Strategic Reserve could be compatible with any of the HLD options for energy trading arrangements presented in this paper. 8.2.4 For the HLD for energy trading arrangements, the main issue is that the existence and operation of the Strategic Reserve should ideally not affect the capacity signals through the energy trading arrangements. Therefore, provisions have to be put in place to keep the Strategic Reserve separate from the energy trading arrangements to mitigate the risk that, by dampening the capacity signals in the energy trading arrangements, more Strategic Reserve is required. This is called, in academic circles, the ‘slippery slope syndrome.’ 8.3 ‘Market-wide’ mechanisms for the recovery of capacity costs 8.3.1 There are a number of different approaches to facilitating the recovery of capacity costs by resources participating in the energy trading arrangements: o Recovery of capacity costs through an energy-only market o Price-based CRM o Quantity-based CRM, which can take the form of capacity auctions, capacity obligations or reliability options. 8.3.2 In addition, there is scope for central one-off tendering for specific generation capacity (e.g. new CCGT) that then participates in the energy trading arrangements as explicitly allowed for under the Security of Supply Directive. However, this is not an option being taken forward at this stage. Energy-only market 8.3.3 Under this approach, capacity costs are recovered through the energy trading arrangements. High spot prices (potentially as high as the value of lost load to consumers) are used to reward resources that are able to help balance supply and demand at times of system stress. 8.3.4 In many European countries, questions have been raised over whether higher levels of wind and solar generation will weaken the ability of energy-only market solutions to deliver strong enough incentives for capacity adequacy. Ultimately, this approach relies on providers of capacity having enough confidence when making (dis)investment decisions that they will be able to capture sufficient value of scarcity from spot energy prices. For example, as conventional generation now typically relies on a smaller number of hours to cover fixed and capital costs, this can give rise to significant increases in revenue volatility and scarcity rent levels. 8.3.5 Without tools to manage the revenue volatility, this can translates into greater risk and higher cost of capital for flexible or back-up capacity, which is ultimately to the detriment of end consumers. An example of risk management tool would be the development of energy options (traded between market participants) to help provide capacity providers with a more certain revenue stream (through the option fee) in exchange for agreeing a fixed (strike) price for delivering electricity when called upon by the option holder. 8.3.6 Typically, energy-only markets have been more associated with more decentralised sets of trading arrangements, generally with increased reliance on Strategic Reserve. Price-based 8.3.7 The current CRM in the SEM is an example of a price-based CRM. It provides a separate revenue stream for capacity providers that supplements any infra-marginal rent earned from the energy market. Similarly, energy buyers pay an additional charge on top of their payments in the energy market. 8.3.8 It typically involves a regulated approach to determining the average annual capacity price. There are then different approaches to how this is spread through the year to reward capacity available to the system at the times of most need. This typically balances ex-ante and ex-post factors. Quantity-based 8.3.9 There are three types of quantity-based CRM that can be used to reward capacity participating in the energy trading arrangements – capacity auctions, capacity obligations, and reliability options. 8.3.10 The first is the centralised capacity auction model, such as the scheme planned for introduction in Great Britain. Essentially, a central agency (e.g. the regulator or the TSO) sets a required capacity volume for a defined period of time, based on an assessment of generation adequacy. A central auction is then to run to procure this required capacity volume. 8.3.11 The capacity procured in the auction receives an upfront payment (based on the clearing price in the auction). On the flipside, it faces a penalty if this capacity is not delivered to the system at times of system stress (however defined). 8.3.12 Some of the key factors that determine the relative attractiveness of this scheme for capacity providers are the definition of periods of system stress and the penalty for non-delivery of capacity at those periods. 8.3.13 As a more centralised approach to capacity procurement, the capacity auctions model may seem to fit more naturally with the more centralised approaches to the design of energy trading arrangements. However, this type of scheme is being introduced in Great Britain, which does not have a centralised set of trading arrangements for energy. 8.3.14 The second option for a quantity-based CRM is a capacity obligation scheme, such as the scheme planned for introduction in France. Under a capacity obligation scheme, electricity suppliers would have to provide certificates showing that they had contracted with capacity resources up to a specified level of capacity (typically linked to their contribution for peak demand). Again, a penalty is levied if this capacity is not delivered to the system at times of system stress (however defined). 8.3.15 As with the capacity auctions scheme, some of the key factors that determine the relative attractiveness of this scheme for capacity providers are the definition of periods of system stress and the penalty for non-delivery of capacity at those periods. 8.3.16 A capacity obligations approach would seem to fit better with a more decentralised approach to the design of energy trading arrangements, as it allows suppliers more choice in the markets and timeframes over which they procure their capacity certificates. 8.3.17 The third approach to quantity-based CRMs is the reliability options model (as proposed in Italy), where these options are procured by a central agency. Again, a central agency (e.g. the regulator or the TSO) sets a required capacity volume for a defined period of time, based on an assessment of generation adequacy. A central auction is then to run to procure this required capacity volume. 8.3.18 In exchange for an upfront payment, the capacity holding reliability options effectively enters into a one-way CfD against a defined reference price. This means that when the reference price is above the strike price, the supported capacity has to pay back the difference. When the reference price is below the strike price, then no payments are made. 8.3.19 This means that under this mechanism, the supported capacity is incentivised to be available at times of high energy prices. 8.3.20 This approach would seem to fit more closely with centralised energy trading arrangements that produce a strong reference price (against which the CfD can be struck). 9 GLOSSARY Balance Responsible Party means a market participant or its chosen representative responsible for its imbalances Market Participant means market participant within the meaning of the Regulation (EU) No 1227/2011 of the European Parliament and of the Council of 25 October 2011 on wholesale market integrity and transparency. Unit Commitment means scheduling of generation or load resource for each time interval representing among others: running state of unit; load generation level; and switching states of automatic regulation system. Unit commitment aims at scheduling the most cost-effective combination of dispatchable generation and demand resources to meet forecasted load and reserve requirements, while complying with resources and transmission constraints. Balancing Market means the entirety of institutional, commercial and operational arrangements that establish market-based management of the function of Balancing within the framework of the European Network Codes. Imbalance Settlement means a financial settlement mechanism aiming at charging or paying Balance Responsible Parties for their Imbalances. Unit-based bid means the bid submitted by a Market Participant that corresponds to potential output from a single generating unit. Portfolio-based bid means the bid submitted by a Market Participant that could correspond to the combined output from one or more generating units that are part of the Market Participant’s portfolio. Dispatch means the process of determining individual output leading to the physical issuing of instructions to connect, disconnect, increase or decrease output of a generating unit. Nomination means the market participant’s desired position to inform the TSO about the anticipated output. Scheduling means the process for disseminating the anticipated output of all generating units or portfolios. Market schedule means the outcome of the scheduling process. Simple bid means a simple price-quantity bid (ie. 50MW for the price of 40€/MWh). Block bid means a bid that refers to more than one hour, potentially with variable output over different periods and has to be accepted as a whole. Sophisticated bid means a simple sub-order with additional complex conditions (ie. Minimum income condition, load gradient, scheduled stop). Regulated bid means a bid that is subject to bidding rules such as price caps and SRMC bidding principles. Unit-based bidding means the process over which a Market Participant submits bid(s) that correspond to potential output from a single generating unit. Portfolio-based bidding means the process over which a Market Participant submits bid(s) that correspond to the combined output from one or more generating units and/or the demand side that are part of the Market Participant’s portfolio. Financial Transmission Right means the financial instrument that market participants can use to hedge against price risk arising from congestion in the Day-Ahead Market. For FTR holders it forms an obligation to pay or a right to receive the congestion the Day-Ahead congestion price for the associated energy flow Physical Transmission Right means the instrument that market participants can use to secure long-term physical access on an interconnector. For PTR holders it forms a right to use the associated interconnector capacity for energy trading 10 ABBREVIATIONS DAM Day-Ahead Market DA Day-Ahead IDM Intraday Market ID Intraday TSO Transmission System Operator NEMO Nominated Electricity Market Operator UIOSI Use-It-Or-Sell-It UIOLI Use-It-Or-Lose-It MCO Market Coupling Operator SRMC Short-run Marginla Cost PCR Price Coupling of Regions CRM Capacity Remuneration Mechanism RES Renewable Energy Sources IC Interconnector