11/02/2016. The Scheduling & Dispatch Process in I-SEM - Design Interpretation

Transcription

1 11/02/2016 The Scheduling & Dispatch Process in I-SEM - Design Interpretation

2 Release Date Version No. Summary of Changes 11/02/ Design Interpretation document published for discussion at Market Rules Working Group 5 on 25/26 th February 2016 CONTENTS 1 Introduction Requirements SEM Committee Decisions Statutory Requirements Multiple Objectives Background Information Power System Constraints The Scheduling & Dispatch Process Today The Scheduling and Dispatch Process in I-SEM Overview Inputs Process Publications

3 1 INTRODUCTION This document sets out a high level description of the proposed Scheduling and Dispatch process in I-SEM. Scheduling and dispatch is the process by which, based on commercial bids and offers submitted by market participants and other market and system information, the TSOs determine requirements and take actions (issue dispatch instructions) to facilitate the operation of the market, maintain system security, maximise the output of priority dispatch generation and meet other statutory requirements. Unlike current practice in the SEM, where the scheduling and dispatch process is largely independent of the market scheduling process, in I-SEM, participant balancing quantities and imbalance prices in the Balancing Market will be directly affected by the scheduling and dispatch process. There will also be the expectation that the market should resolve the energy demand/supply balance through trading in the ex-ante day-ahead and intraday markets. This will require significant changes in the scheduling and dispatch processes from SEM to I-SEM. The focus of this document is the scheduling and dispatch process commencing after the outcome of the day-ahead market is known to the TSOs (13:30 day-ahead) through to real-time operation of the power system. This is the period spanning the opening of the intraday and balancing markets and the hour post intraday and balancing market gate closure. There are a number of other I-SEM functions linked to the scheduling and dispatch process which are considered in separate market rules documents. These include Imbalance Pricing (which describes how the imbalance price is determined) and Imbalance settlement (which covers settlement of balancing actions and imbalances). There are also Network Code related requirements such as the creation of the Individual Grid Model that drive some of the inputs to the process described in this document. The approach described here represents the starting point for the development of scheduling and dispatch rules through the I-SEM Market Rules Working Group process. This process allows for the development of these rules over the coming months with some specific topics addressed at later Working Groups. The approach will also be informed by the outcome of on-going implementation design and development work with system providers. 2

4 2 REQUIREMENTS 2.1 SEM COMMITTEE DECISIONS The I-SEM design provides for mandatory participation of market participants in the TSOs scheduling and dispatch process which spans the intraday and balancing market timeframes. The SEM Committee ETA decision paper (SEM ) contains a number of guiding principles related to this scheduling and dispatch process: Insofar as it is possible, the ex ante markets should be left to resolve the energy supply/demand balance. The TSOs should not take any action prior to [Balancing Market] gate closure unless it is for reasons of system security e.g. reserves, for priority dispatch or for other statutory requirements. Costs for non-energy actions are economically incurred. Minimise the cost of balancing the system given the PNs at [Balancing Market] gate closure. In addition there are a number of related requirements in both the I-SEM HLD (SEM a) and ETA decision papers that impact on the scheduling & dispatch process: Participation in the ex ante markets is not mandatory, Only dispatchable generation and demand is required to submit PNs (i.e. wind and non dispatchable demand will not be required to submit PNs), PNs will be partially delinked. This means that PNs only have to be linked to ex ante trades at gate closure (i.e. FPN should equal traded volumes). Prior to gate closure, a participant s PN submission should be its best estimate of its FPN (i.e. should reflect their expected final ex ante trades). 2.2 STATUTORY REQUIREMENTS While the I-SEM design will result in significant changes to the market, it does not change obligations on the TSOs with respect to system security, the treatment of priority dispatch or other statutory requirements arising from the Network Codes. It is therefore important that the scheduling process complies with these other obligations while seeking to achieve the principles described in the ETA decision paper. The following table illustrates the high-level objectives for the scheduling and dispatch process as currently implemented in the SEM and as proposed for the I-SEM: 3

5 Objective SEM I-SEM Security Priority Dispatch Other Statutory Requirements Statutory requirement to maintain system security and meet all reasonable demands for electricity (IRL). SI 445 of 2000 (IRL) SI 231 of 1992 (NI) Absolute interpretation of Priority Dispatch generation European Directive 2009/28/EC SI 147 of 2011 / SI 426 of 2014 (IRL) SR 385 of 2012 (NI) SEM Capacity Allocation and Congestion Management (CACM) Regulation (EU) No Change No Change No Change Economics Minimisation of the cost of generation (IRL) SI 445 of 2000 (IRL) SI 231 of 1992 (NI) SEM /63 Priority dispatch order I-SEM HLD: Minimisation of cost of deviating from participant Physical Nominations I-SEM ETA Decision: Insofar as it is possible, the ex ante markets should be left to resolve the energy supply/demand balance. The TSOs should not take any action prior to [Balancing Market] gate closure unless it is for reasons of system security e.g. reserves, for priority dispatch or for other statutory requirements. Costs for non-energy actions are economically incurred. Minimise the cost of balancing the system given the PNs at [Balancing Market] gate closure. 4

6 2.3 MULTIPLE OBJECTIVES With the scheduling and dispatch process necessarily running in parallel with the intraday market, it has been recognised that there are potential interactions between TSO actions and the intraday market. These were identified in the I-SEM ETA decision paper with specific guidelines set out as summarised in section 2.1. These guidelines split the objective of the scheduling and dispatch process into two timeframes both of which sit under associated statutory requirements: Before intraday gate closure: energy balancing actions should be taken as late as possible the cost of constraint (non-energy) actions should be minimised After intraday gate closure: The cost of all energy and non-energy actions should be minimised. In practice, however, actions to balance energy requirements are not fully distinguishable from nonenergy actions, or vice versa. The scheduling and dispatch of bids and offers to balance energy can cause or relieve constraints or other system security requirements. Similarly, non-energy actions, taken to maintain system security, can increase or decrease energy imbalances. In addition, priority dispatch actions can affect energy imbalances and/or system security. The challenge in the scheduling and dispatch process is in simultaneously solving for these objectives while respecting the over-arching statutory requirements as illustrated in the figure below. 5

7 3 BACKGROUND INFORMATION 3.1 POWER SYSTEM CONSTRAINTS The power system of Ireland and Northern Ireland has a number of characteristics that mean its operation is subject to a large number of constraints that have a significant impact on the scheduling and dispatch process. These characteristics include: small island system, weakly interconnected, large unit/interconnector size relative to demand, relatively inflexible generating units (long notification times when compared to similar GB plant) and high levels of variable renewable generation that has priority dispatch status. The consequence of the security, priority and other statutory requirements is that there are a large number of active operational constraints that drive TSO dispatch actions. An illustration of the reasons for dispatch actions is shown in the following table. Security Priority Statutory Reserve Ramping (Operating Margin) Voltage Thermal Stability Short Circuit Supply=Demand Wind Hydro Solar Tidal Biomass Waste to energy High Eff. CHP Peat Safety CACM: generation re-dispatch and countertrading to facilitate cross-border capacity The impact of these constraints on the scheduling and dispatch process in SEM today is that there is observed to be a significant deviation between the unconstrained market schedule and actual dispatch (ref. 40 % energy volume in SEMC Constraint Analysis report for 2013, SEM ). 3.2 THE SCHEDULING & DISPATCH PROCESS TODAY In the current SEM, the scheduling and dispatch process is largely independent of the market scheduling process (with the exception of interconnector flows). 6

8 Schedules are determined using the TSOs Reserve Constrained Unit Commitment (RCUC) tool with market participant commercial and technical data forming an input to the process. RCUC then determines a secure schedule based on an objective to minimise the overall production cost. Dispatch instructions are then issued in line with this schedule subject to changes to system conditions. 7

9 4 THE SCHEDULING AND DISPATCH PROCESS IN I-SEM 4.1 OVERVIEW The diagram below provides a high level overview of the proposed scheduling and dispatch process implementation in I-SEM. This will be a continual, rolling process from day-ahead through intraday to the balancing market and real time dispatch. The following sections describe the inputs to this process, the process itself and its outputs. At the core of the TSOs scheduling and dispatch process are the Security Constrained Unit Commitment (SCUC) and Security Constrained Economic Dispatch (SCED) tools which are replacing the existing Reserve Constrained Unit Commitment (RCUC) tool. These tools take inputs from market participants (such as PNs, bids and offers) and TSO data such as forecasts and models of constraints and determine schedules (plans) that feed dispatch decisions issued to market participants. 8

10 4.2 INPUTS Inputs to the scheduling and dispatch process are listed below. Many of these inputs are discussed in the Bids and Offers Design Interpretation paper, the information presented in this paper relates to inputs not addressed elsewhere. Registration Data Technical Offer Data Ancillary Services / System Services Technical Capabilities Availabilities PNs Bids & Offers Ancillary Services / System Services Commercial Data Interconnector Schedules Forecasts Constraints SO-SO Trade Volumes and Prices Units Under Test REGISTRATION DATA Registration is due for discussion at Market Rules Working Group 9 on 28 th July A number of new registration parameters are under consideration and may be brought forward to this Working Group. As an example, dispatchable is one of the new registration parameters currently under consideration as described below. Dispatchable would be used to indicate whether or not a market participant is deemed to be fully dispatchable by the TSO. This requirement is primarily driven by the need to allow wind units to elect, if they wish, to become the equivalent of price makers rather than price takers (these registration categories will not exist in I-SEM). Dispatchable means that the TSO can issue MW set-point instructions to a market participant via an appropriate interface and that the market participant will follow these instructions. Currently only conventional generation falls in to this category with the TSO issuing dispatch instructions via EDIL (Electronic Dispatch Instruction Logger) to a unit operator who then actively implements the instruction. In the case of wind, the TSO can currently only apply a limit to the output of a wind unit via the TSOs EMS (Energy Management System) directly to the wind unit control system. This approach does not allow for active dispatch of a wind unit to their PN or the dispatch of balancing actions (incs and decs). In order for a wind unit to deemed dispatchable it would need to have the appropriate TSO dispatch interface in place and to have completed a period of testing to demonstrate the ability to respond to dispatch instructions (as any other dispatchable unit). 9

11 A wind unit that is non-dispatchable may submit a PN but not commercial offer data to the Balancing Market. The PN will be used for information purposes only, potentially being used to inform the TSOs wind forecast. A wind unit that elects to be dispatchable will be required to submit PNs and Balancing Market commercial offer data and will be dispatched by the TSO as any other dispatchable unit TECHNICAL OFFER DATA The format and timing of Technical Offer data submissions are addressed in the Bids and Offers Design Interpretation paper ANCILLARY SERVICES / SYSTEM SERVICES CAPABILITIES Market participants will provide technical capabilities with respect to the provision of mandatory and contracted Ancillary Services/System Services. As today, these capabilities will be managed through Ancillary Services/System Services contractual arrangement so, unlike TOD, they will not be submitted and managed via the Market Participant Interface (MPI) AVAILABILITIES As today, market participants will be required to submit their forecast technical availability (maximum availability, minimum stable generation and minimum output) for use in the scheduling process with real-time updates provided for use in the real-time dispatch process. Forecast availability (maximum availability, minimum stable generation and minimum output) will be submitted by market participants to the TSOs via a new MPI. This information should extend from the beginning of the next open intraday period through to the end of D+2 so that there will always be at least 48 hours of availability data submitted. For example, on Tuesday at 15:00, availability information will have been submitted up to at least 22:59 on Thursday. Availability data is required to D+2 to facilitate the creation of the Individual Grid Model (IGM) and Common Grid Model (CGM) as mandated under the Capacity Calculation and Congestion Management (CACM) Regulation (further information can be found here Forecast availability information is currently provided at trading period granularity. The suitability of this level of granularity remains under consideration given that, for example, PNs will be provided at 1 minute granularity. 10

12 Market participants will be required to provide continual updates to their availability i.e. availability declarations are not related to any gate closure but should always reflect the best forecast availability information. Real-time availability re-declarations will continue to be independently provided by market participants via the Electronic Dispatch Instruction Logger (EDIL) interface with the TSOs. It is the responsibility of market participants to ensure that real time availability re-declarations align with forecast availability. For example, if a unit trips, the market participant will re-declare its availability to zero in EDIL and, if appropriate, update the forecast availability (to D+2) via the MPI. As today, market participants will also be required to declare real-time capabilities for Ancillary Services/System Services in EDIL. For example, reactive power capability ranges or operating reserve capabilities that change in real-time must be redeclared via EDIL. While there is no MPI capability declaration requirement for these services, any medium to longer term change to capability should be notified to the TSO (managed via separate contractual arrangements). Further discussion on submission of data is due to take place at Market Rules Working Group 7 on the 12 th May PNS PNs are the starting point of the scheduling & dispatch process. The SEMC ETA decision paper sets out the following general requirements related to PNs: The PNs should at all times be the participant s best estimate of its intended level of generation and/or consumption, reflecting its expected ex ante contracted position. Non dispatchable renewables and demand will not be required to submit PNs even if they have or expect to trade in the ex ante markets the TSOs will effectively be using their own forecasts as an implicit PN in their assessment of system security. 11

13 All dispatchable market participants will be required to submit PNs. Non-dispatchable market participants will be able to submit PNs however these may only be used for information purposes, say to inform the TSOs forecast. PN submission timing and format is addressed in the Bids and Offers Design Interpretation paper BIDS AND OFFERS The format and timing of Bid and Offer submissions are addressed in the Bids and Offers Design Interpretation paper ANCILLARY SERVICES / SYSTEM SERVICES COMMERCIAL DATA The scheduling and dispatch of Ancillary Services is currently based on a unit s technical capability and its commercial offer data for energy only. As all Ancillary Services capability payments are currently remunerated at common tariffs (i.e. a fixed rate per service applied to all service providers), there is no requirement today to account for different Ancillary Service capability payment rates in the scheduling and dispatch process. This may change in I-SEM given the proposed approach to the procurement of System Services (System Services encompass the seven existing Ancillary Services and seven new services) via competitive auctions. This new approach may result in different System Service capability payments per service, per service provider and require co-optimisation of the energy costs with System Service costs in the scheduling and dispatch process. A decision on the System Services auction design is due to be made by the SEM Committee in May It is proposed that, based on the outcome of this decision, there will be an update provided at the Market Rules Working Group meeting subsequent to this decision INTERCONNECTOR SCHEDULES Details on the implementation of interconnector schedules remain under consideration. An update will be provided at the Market Rules Working Group on the 7 th April FORECASTS In general, TSO forecasts of consumption and production from non-dispatchable market participants (mainly demand and wind) will be used in the scheduling process. 12

14 As allowed for under the SEMC ETA decision (SEM section 4.5) PNs may be submitted by non-dispatchable market participants for information purposes. The TSOs may use these PNs in their forecasts if such information is considered more reliable and accurate than the TSOs forecast. The use of such information would be subject to a period of performance monitoring by the TSOs. Further discussion on TSO forecasts is due to take place at Market Rules Working Group 6 on the 7 th April CONSTRAINTS Market participants will be required to submit physically feasible PNs to the TSOs based on the outcome, or expected outcome, of the ex-ante markets. In this case physically feasible is with respect to the market participant s own plant technical capability, for example respecting plant ramp rates and plant capacity limits. However the PNs do not have to be feasible from a power system perspective, i.e. they do not have to respect transmission line powerflow limits nor are they required to allow for the provision of reserve headroom. Also, PNs may not reflect the optimal dispatch for facilitating priority dispatch plant nor a feasible dispatch for facilitating maximum interconnector transfers. Addressing these other constraints is the core function of the scheduling and dispatch process. Constraints can broadly be categorised into three main headings: Security, Priority Dispatch and Other Statutory Requirements as summarised in section 3.1. In general, the treatment of these constraints is not directly affected by the I-SEM market arrangements although the new market arrangements may impact on the extent to which constraints bind and the underlying cost of constraints. Further information on these constraints is provided below. Security Constraints: EirGrid publishes a list of security constraints and a description of their implementation in a document entitled Operational Constraints Update (see Operations\Constraints Update in the library). Priority Dispatch: Rules for the implementation of Priority dispatch are contained in SEMC decision SEM and EirGrid publication Policy for implementing scheduling & dispatch decisions SEM Other Statutory Requirements: The main new requirement here is related to a requirement under Network Code CACM for the TSOs to develop a common methodology for coordinated re-dispatching and countertrading as related to cross-zonal capacity. Work on the development of this methodology is underway via a regional working group. Examples of security constraints on the Ireland and Northern Ireland power system are illustrated in the diagram below. 13

15 These constraints are modelled in the scheduling and dispatch tools (SCUC and SCED) so that the resulting schedule/dispatch respects the limits imposed by the constraints SO SO TRADES: AVAILABLE VOLUMES AND PRICES While not specifically addressed in the I-SEM market design, arrangements for cross-zonal trading of energy are expected to be maintained in I-SEM via System Operator to System Operator (SO-SO) trading arrangements in the post balancing market gate closure timeframe (i.e. in the last hour to real-time) UNITS UNDER TEST The approach to submission of data for Units Under Test in I-SEM is addressed in the Bids and Offers Design Interpretation paper. The notice times for submission of this data come under Grid Code requirements, therefore the PN profile and proposed times would need to be submitted and agreed with the TSO according to the required timelines in advance of their submission through the balancing market offers and bids. 14

16 4.3 PROCESS The input discussed in section 4.2 feed in to the scheduling and dispatch process outlined in this section SCHEDULING AND DISPATCH In seeking to achieve the I-SEM objectives, it is important to distinguish between scheduling and dispatch. In the current SEM, the structure of the market means that the two processes can be considered two parts of a single process. However, in the I-SEM, because of the short gate closure time (relative to the notice times required to synchronise some generation resources), and the different objectives before and after gate closure, it is necessary to distinguish more explicitly between scheduling and dispatch. Scheduling can be thought of as the positioning of resources to allow the system to be securely dispatched. Given a set of PNs, scheduling is the process of identifying the commitment and decommitment decisions that are necessary to enable all the system constraints be satisfied (e.g. security, priority dispatch and other statutory reasons). Since some generators have long notice times to synchronise (up to 18 hours), the scheduling process must start well in advance of real-time but the indicative schedule can and will change as PNs and prices change. Dispatch can be thought of as the process of balancing supply and demand in real-time. In general this happens after gate closure. Given the final PNs and the actual status of units, the dispatch process modifies the output of units in accordance with inc/dec offers to ensure system balance (keeping the frequency at 50Hz) while meeting all the security constraints and maximising the output from priority units. When determining a secure schedule, it is necessary to also determine the dispatch of resources for each period being considered to ensure that all constraints are met and to satisfy the objective of minimising the cost of constraint actions. However, any such schedule is just indicative it is expected that the actual dispatch will not be determined until after the gate has closed as this allows the final PNs and inc/dec offers to be considered PN VALIDATION There is a requirement that the PNs submitted by market participants are technically feasible from the perspective of their plant capability. A level of validation will also be performed by the TSOs on receipt of the PNs. This will include: Verifying that the PNs indicating a unit start-up take into account all relevant technical parameters of the generating unit (e.g. notification time, dwell times, soak times and loading rates) Verifying that changes to PNs for a unit are consistent with the unit s relevant technical parameters (e.g. ramp up rates and ramp down rates) 15

17 Verifying that the PNs indicating a unit shut-down take into account all relevant technical parameters of the unit (e.g. deloading rates and breakpoints) Verifying the profile defined by submitted PNs within each trading period is consistent with the submitted forecast maximum availability, forecast minimum stable generation and forecast minimum output for the corresponding trading period(s). Verifying the profile defined by submitted PNs is consistent with heat states, minimum on times and minimum off times Further consideration is being given to whether or not the validation is performed with respect to the market position or the dispatched position of the unit. market position validation would assess the feasibility of a PN submission against the previously submitted PN but would not account for the physical dispatch of the unit. dispatched position validation would assess the feasibility of a PN submission against the current dispatch position of the unit rather than a previously submitted PN. A validation report will be produced by the TSOs and any PN infeasibility will be notified to the relevant market participant. If a PN submission is deemed infeasible, the TSOs will reject the entire PN submission and will revert to using the last validated and accepted set of PNs. For the avoidance of doubt, within the scheduling and dispatch process there is no validation of the PN against ex-ante contracted positions SCHEDULING TO THE FORECAST DEMAND Since participation in the ex ante markets is not mandatory, it is expected that the PNs (explicit and implicit) will generally not net to zero, i.e. the market will generally not be exactly balanced. However, supply/demand balance is the fundamental constraint of the scheduling process. It therefore follows that the imbalance must be addressed in the implementation of the scheduling process. It is proposed that the scheduling process will be based on the best demand forecast information rather than the sum of the PNs. For example, if the aggregate PNs received for the peak of the day at 18:00 are 5000 MW but the demand forecast for the peak is 5400 MW there is an imbalance (shortfall) of 400 MW. The scheduling process will seek to resolve this imbalance by scheduling an 16

18 additional 400 MW of generation and/or dispatchable demand reduction. Resolving this imbalance is one of the many constraints that the scheduling process must address. The scheduled actions to resolve the imbalance become part of the overall constrained solution and consequently it is not possible to distinguish between actions that are scheduled to resolve the energy balance from actions to resolve constraints System Demand Total PNs (incl wind) :00 02:00 04:00 06:00 08:00 10:00 12:00 14:00 16:00 18:00 20:00 22: CONTINUAL SCHEDULING PROCESS The current SEM has two day-ahead gate closures followed by one within-day gate closure, which allows updates to prices for the second half of the trading day. The scheduling process begins at the day-ahead stage, with refinements and revisions only when required if prices, nominations or forecasts change. The day-ahead indicative operational schedule is therefore relatively stable and is usually a good indicator of the actual schedule. In contrast, the I-SEM intraday market and balancing market will have shorter gate closure times and therefore more opportunities for market participants to change prices and positions after the dayahead market. This will necessitate a continuous scheduling process to ensure the latest market information feeds into the actual dispatch. The scheduling process will commence at the day ahead stage, with the submission of initial PNs by market participants following the results of the dayahead market. The operational schedule at this stage will be very provisional as it will change as PNs evolve (perhaps significantly) with activity in the intraday market. The continuous nature of the process means that whenever a scheduling decision is made, it will be on the basis of the latest market information available (PNs and prices); also, whenever the market positions change (indicated by updated PNs or prices), the schedule will be reassessed accordingly and revised if appropriate. 17

19 4.3.5 OBJECTIVE FUNCTION As outlined in section 2.3 there are multiple objectives associated with the scheduling and dispatch process. However, from an implementation perspective the objective function in the scheduling and dispatch tools (SCUC and SCED) is to satisfy all constraints (including demand/supply balance) while minimising the cost of deviating from market participant PNs. As discussed in that section, there is no way to distinguish between energy and non-energy actions in the scheduling process and apply different scheduling rules to each. However, in order to address the desire to minimise early energy dispatch actions (which result from long notice units being scheduled ahead of shorter notice units on an economic basis) it is proposed to introduce a weighting factor to favour scheduling of shorter notice units for all actions this is discussed in section WEIGHTING TOWARDS SHORTER NOTICE ACTIONS One of the I-SEM objectives is that the day-ahead and intraday markets should be the primary mechanisms by which the energy supply/demand balance is resolved. If the market finds a balanced energy position through the ex-ante markets, the need for TSO energy actions will be minimised. However, if the market is not balanced, there is a risk that the proposed approach could result in early actions that could dilute the signals to market participants or appear to unduly interfere with the intraday market. For example, a large imbalance indicated by the initial PNs may suggest the need for the TSO to start up additional generating plant and if, based on commercial offer data, generator units with long notice times appear to offer the lowest cost option in rebalancing the system, such decisions may need to be taken well before final gate closure. However, this could preempt potential trading activity in the intraday market and/or lead to sub-optimal outcomes if the supply/demand balance subsequently changes prior to real time dispatch. It is, therefore, proposed to include a long notice adjustment factor (LNAF) that effectively applies a weighting to the costs of off-line long notice generators to reduce the propensity for taking early commitment actions in the scheduling process. The LNAF will apply to parts of a participant s offer data (probably just start costs but may also need to include no-load costs) in the scheduling process. This will tend to reduce the attraction to early decisions to start up long notice plant over the use of shorter notice units. If the scheduler has no choice but to start a long notice unit to satisfy a security constraint then it will do so. However, given a choice of a number of resources with the same (or similar) cost, application of the LNAF will tend to favour shorter notice resources in the scheduling process. 18

20 LNAF 1 threshold Notice time This curve is provided for illustration purposes only. The function is likely to be a stepwise curve. The calculation of the long notice adjustment factor (LNAF) will have the following high-level features: LNAF = 1 if unit has PN > 0 or if unit has notice time < threshold (e.g. gate closure time) For units with notice time > threshold (and PN = 0), the LNAF will be greater than 1 and will increase as notice time increases. Since the LNAF will only be used in the scheduling process for off-line units, those units with long notice requirements will have an additional incentive to trade in the intraday market rather than waiting to be scheduled by the TSO. It should be noted that the LNAF would be used in the scheduling process only no LNAF adjustment would apply in real-time dispatch or in settlement. Incorporating the LNAF into the proposed approach should result in a reduction in early actions. However, since all actions (both energy and non-energy) would be affected by the factor, the reduction in early energy actions will potentially result in increased costs of non-energy actions. The extent of the trade-off will be determined by the steepness of the LNAF function IMBALANCE INDEX Energy actions should only arise when there is an energy imbalance. If the imbalance is zero, all actions should be non-energy actions and the LNAF would not be required as the schedule should seek to resolve non-energy actions at least cost. It is therefore also proposed that the LNAF function incorporates an imbalance index, which would act to flatten the LNAF function when imbalances are small but generates a steep LNAF when imbalances are large. This should help target the LNAF at times when early energy actions are more likely and dampen its effect when it is not required. This concept is illustrated in the figure below. 19

21 LNAF High Imbalance Index 1 Low Imbalance Index threshold Notice time This curve is provided for illustration purposes only. The function is likely to be a stepwise curve. The detailed implementation of the LNAF and associated imbalance index are still under development, however it is being designed to allow flexibility in the setting of its associated parameters. Careful tuning of these parameters will be required to ensure the desired market outcomes without causing unexpected results such as excessive dispatch balancing costs RESPECTING NOTIFICATION TIMES Where the schedule indicates that commitment of a generator is required, this decision is not finalised until the latest time possible (i.e., based on the notice time required). When combined with the incentives to shorten notice times, the last time to call approach allows the market the maximum possible time to resolve imbalances. For example: the scheduling tool will provide advice on when a unit is required: post receipt of day-ahead PNs, the schedule run at, say, 15:00 indicates a requirement for Unit X (which has a PN of zero for the day) to be on at 06:00. The unit has a notification time (i.e. the notice time required for the unit to synchronise) of 4 hrs No action regarding Unit X is taken by the TSO at this time This indicative schedule may be published but is not a firm indication of the requirement. The TSO continues to assess the requirement for the unit until the timing of the decision becomes binding. The scheduling run at 01:00 (based on latest PNs etc) indicates the same requirement for Unit X to be on at 06:00 The TSO issues a sync instruction to Unit X at 02:00 (i.e. requirement time less notification time) 20

22 One of the impacts of this approach is that indicative schedules that may be published by the TSOs will not provide the same level of certainty to market participants on expected running as they do today DISPATCH Central dispatch by the TSOs remains in place in I-SEM market participants will follow the dispatch instructions issued by the TSOs. These instructions will seek to minimise the cost of deviation from the PNs but there will inevitably be requirements to move away from the PNs to manage constraints. Note, in GB, market participants generally follow their PNs unless told otherwise by the TSO this is not the case in SEM or I-SEM market participants will not connect to the system, disconnect from the system or adjust their output unless instructed to do so by the TSO (or as required to automatically respond to frequency deviations). EDIL will continue to be used for the issue of dispatch instructions to dispatchable units. Wind units will continue to receive constraint and curtailment instructions from the TSOs Wind Dispatch Tool. Dispatch instructions will in general remain open i.e. go to and stay at x MW until further notice All instruction types issued today will remain valid in I-SEM (e.g. synchronise, de-synchronise, MW set-point, ancillary services instructions etc.). The implementation of some new instruction types are currently under consideration: Follow PN : while in general it is expected that the TSO will issue all sync, de-sync and MW instructions explicitly, in some instances it may be more practical to issue a follow PN instruction. In this instance a unit would self-dispatch to follow its last submitted PN profile until instructed to do otherwise by the TSO. Go to and stay at x MW until at least time t : this instruction would allow for the duration of an otherwise open instruction to be defined and allows for different treatment of the instruction in settlement (an open instruction is treated as acceptance of the minimum energy quantity given relevant technical offer data whereas the until at least time t instruction allows for the energy quantity to be increased beyond the technical minimum) If non-dispatchable units such as wind wish to be deemed dispatchable, they will require a new dispatch interface (i.e. EDIL). 21

23 UNITS UNDER TEST For agreed test profiles (reflected as PNs within an associated flagged test period) the unit will be dispatched to the test profile unless for system security reasons the unit is required to change their output MANAGING EVENTS Consideration will be given to the I-SEM impact on management of scheduling and dispatch related events at Market Rules Working Group 6 on 7 th April Such events might include: Transmission contingency events leading to new constraints Unit trips Interconnector trips Emergency instructions Demand control 22

24 4.4 PUBLICATIONS INFORMATION PROVIDED BY EIRGRID Publications will be discussed at Market Rules Working Group 7 on 12th May Information publications related to the scheduling and dispatch process might include: Demand forecasts / actual / historical Wind forecasts / actual / historical Imbalance forecasts / actual / historical Constraint information PNs, Bids and Offers, Technical Offer Data Indicative Operational Schedules Dispatch Instructions Imbalance prices SO-SO trade prices and volumes Market messages / warnings 23