Dispatching Variable Generation Resources

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1 Dispatching Variable Generation Resources A Discussion Paper for Stakeholder Engagement 91 (Renewable Integration)

2 Table of Contents Introduction... 3 IESO Dispatch Processes... 5 Registration... 5 Dispatch Data... 6 The Scheduling Process... 7 Market Schedules... 8 Constrained Schedules... 8 Timelines Compliance Congestion Management Settlement Credits Next Steps Appendix A Renewable Integration Design Principles Appendix B Discussion Questions April 28, 2011 Public Page 2 of 18

3 Introduction Ontario s Long Term Energy Plan reinforces the investment focus on renewable generation under the Green Energy and Green Economy Act (GEA) and the Ontario Power Authority s Feed-In-Tariff (FIT) program. The Plan acknowledges the significant commitments made to date - 5,800 MW of variable generation projects, primarily wind, are underway and are expected to be in commercial operation by the end of 2012, with 10,700 MW targeted for This rapid deployment of renewables across the province will fundamentally change the characteristics of the power system, challenging the IESO s ability to maintain reliable and cost-efficient operations. To meet this challenge, and help capture the benefits of Ontario s investment in variable generation, the IESO is adapting power system operations and the IESO-administered markets to accommodate the influx of renewables. In March of 2011, the IESO, in collaboration with stakeholders in the SE-91 stakeholder engagement process, adopted a series of 11 design principles 1 which will form the basis for the integration of variable generation resources 2 into Ontario s wholesale electricity market. These 11 principles can be broadly grouped into three areas of focus: forecasting, visibility and dispatch. Most notably, from a dispatch perspective was the adoption of the following principles: Principle 7: All variable resources connected to the IESO-Controlled Grid, and embedded variable resources that are registered market participants, will be actively dispatched on a five-minute economic basis. Principle 8: Variable generators will operate within a compliance deadband when ambient conditions offer sufficient fuel. Principle 9: Variable generators will be entitled to Congestion Management Settlement Credit (CMSC) payments. Note: Although SE-91 Principle 10 3 and Principle 11 4 are also related to dispatch they are out of scope for this discussion paper. 1 The approved design principles can be found in Appendix A of this document. 2 For the purposes of this paper, and all discussions in SE-91, variable generators will only refer to wind and solar generators. 3 Principle 10: The IESO may establish various floor prices for offers from baseload generators (e.g. wind, must-run hydro, nuclear, etc.) to ensure efficient dispatches during periods of local and/or global surplus baseload generation (SBG) events. 4 Principle 11: Directly connected variable resources (and embedded resources that are market participants) will be eligible to participate in Operating Reserve and ancillary markets where technically feasible (such integration will be considered on a cost benefit basis, and is not likely to be addressed in the near term). April 28, 2011 Public Page 3 of 18

4 Through these principles, the IESO will treat wind and solar generators which are connected to the IESO-controlled grid, and those embedded wind and solar resources that are registered market participants, in much the same way as conventional resources, such as hydroelectric, nuclear, and natural gas generators. To the greatest extent possible, the IESO intends to make use of existing processes and systems when developing the dispatch framework for wind and solar generators. The purpose of this document is to discuss the IESO s existing dispatch methodology and how the design principles will influence the incorporation of variable generation resources into this methodology. This document will also highlight, through a series of questions, those areas which will require discussion with stakeholders as part of the Dispatch Technical Working Group of the SE-91 stakeholder engagement. April 28, 2011 Public Page 4 of 18

5 IESO Dispatch Processes REGISTRATION Anyone wishing to inject energy into or withdraw energy from, the IESO-controlled grid must become a market participant. From a generator perspective, this registration requirement includes all directly-connected generators, but may also be extended, on a voluntary basis, to generators embedded within a distribution system where such generators wish to participate directly in the IESO-administered markets. It is through this registration process that the IESO captures the information required to facilitate this market participation and ultimately enables the dispatching of these generators. At the highest level, market participants who own generation facilities may register them as one of either dispatchable or self-scheduling, intermittent or transitional scheduling. Dispatchable generators submit offers to supply quantities of energy at various laminations, each with a price that represents their marginal cost to supply that energy. Collectively, these are known as price/quantity pairs, which will be described in the following section. The other types of generators, on the other hand, do not submit the same price/quantity pairs that are submitted by dispatchable generators, but instead submit either a forecast or schedule of their desired production, along with a price at which they reasonably expect to reduce their output to zero. These generators, given their fuel availability, then typically produce energy per their schedule or available fuel (i.e. wind, sun). As part of the registration process, market participants identify the technical aspects of their equipment that may limit their dispatchability within the market. Examples include minimum loading points and minimum run times for combined cycle natural gas plants, and forbidden regions for hydroelectric plants. There may be comparable technical limitations on wind and solar generators that will need to be identified and recorded through the registration process in order to make this information available to the dispatch algorithm. Question: What technical limitations exist for wind and solar generators that must be respected by the dispatch algorithm in order to produce a viable dispatch instruction that can be followed? Based on the design principles adopted by the Renewable Integration (SE-91) stakeholder engagement, the IESO proposes that variable generators that are directly connected to the IESOcontrolled grid be dispatchable. Embedded variable generators who wish to become market participants may also register as dispatchable if they so choose. Note: embedded variable generators subjected to Centralized Forecasting will also have registration requirements. These were stakeholdered under the Visibility Technical Working Group (VTWG). VTWG - April 28, 2011 Public Page 5 of 18

6 DISPATCH DATA Market participants with dispatchable resources participating in the real-time energy market submit offers and bids to the IESO in order to determine the most efficient scheduling of the available resources in the market. These bids and offers are then used by the IESO to economically direct the output of these dispatchable generators and loads through the issuing of dispatch instructions on a 5-minute basis to meet the various operating needs throughout the day. For each hour of the day, each dispatchable facility is given 20 price/quantity pairs to define the market participant s willingness to produce electricity based upon market price within that hour. For example, a generator may find that it is economical to generate more electricity when the market price is higher. Each pair is comprised of a price in $/MW and a quantity in MW and must represent more energy at a price not less than the previous price/quantity pair. Though 20 price/quantity pairs are available, there is no obligation to use all 20. These price/quantity pairs represent the entire range of operation that a dispatchable resource is offering to generate or consume. Below is an example of a price/quantity pair submission: Table 1 - Example of Price/Quantity Pairs Price ($/MW) Quantity (MW) $10 0 $10 25 $15 35 $25 75 The first price/quantity pair always has 0 MW for the quantity and the price for the first and second price/quantity pairs will always be the same. By doing so, the market participant is indicating that if the price reaches $10, it will be willing to produce up to 25 MW. If the price reaches $15, it will be willing to produce up to 35 MW. Similarly, if the price reaches $25, it will be willing to produce up to 75 MW. If a market participant s offers for a generation facility are not expected to change from day-today or from week-to-week, the market participant may submit a standing offer that will stay in effect until an expiration date identified by the market participant at the time of the submission of the standing offer, or until the market participant withdraws or revises the standing offer. Such standing offers must be submitted before 6:00 EST day-ahead, at which time this standing offer is converted into an offer for use in the Day-Ahead Commitment Process. For a variable generator, the range of operation is defined by the technical limitations of the resource and the amount of wind or sunlight that is available. Currently, variable generators are registered as intermittent generators and provide a forecast of expected output in each hour, as well as a price at which they reasonably expect to reduce their output to zero. This may lead one to assume that once variable generators become dispatchable, only two price/quantity pairs are required to represent the range from zero output to their maximum forecasted capability. April 28, 2011 Public Page 6 of 18

7 However, there may be technical limitations, such as a minimum loading point, that could be represented by this first set of price/quantity pairs, with a subsequent pair required to describe the remainder of the generator s forecasted capability. Question: Are two price/quantity pairs sufficient to capture price sensitivity over the entire operating range of a variable generator? In addition to their price sensitivity, dispatchable generators also provide hourly ramp rates which describe their ability to increase or decrease their generation in MW/minute. As this ability to manoeuvre may depend upon the operating point of the resource, dispatchable generators are allowed to submit up to 5 ramp rates to describe their resource s manoeuvrability both in an upwards and downwards direction. Generators also must submit the ramp rate break points, which are the MW output thresholds at which the ramp rate changes for a given facility. Below is an example of a price/quantity pair submission: Table 2 - Example of Ramp Rates Break Quantity (MW) Ramp Rate Up (MW/min) Ramp Rate Down (MW/min) In the example above, the given market participant is indicating that their 100 MW generator can ramp up at 10 MW/min between 0 and 50 MW, 8 MW/min between 50 and 75 MW and 5 MW/min between 75 and 100 MW. Variable generators may require the functionality to identify ramp rates within their operating range, provided that they are based upon a technical limitation of their installed turbines. However, it may also be true that, given the proper fuel conditions, a wind or solar farm may be able to ramp across their entire operating range (i.e. from zero output to maximum forecasted capability) within a single interval, which would make the submission of a ramp rate irrelevant for the purposes of dispatch. Question: Do wind and solar generators require the ability to submit ramp rates and break points? Should the IESO assume a common ramp rate for variable generators as dictated by their fuel type? THE SCHEDULING PROCESS The IESO dispatch algorithm produces two distinct schedules for each registered facility: market schedules, also known as unconstrained schedules, that reflect the economic merit order and constrained schedules which represent the dispatch instructions for each facility. Both April 28, 2011 Public Page 7 of 18

8 market and constrained schedules are calculated in the pre-dispatch timeframe for each hour and for each 5-minute interval in real-time. Market Schedules A facility s market schedule represents how they would have ideally been dispatched based upon their offers or bids. Bids and offers are used to determine the market clearing price for each interval. In the predispatch timeframe, the price is set by determining the cost of securing an incremental MW above the forecasted demand and reserve requirements. In real-time, the market schedule considers the actual demand, as well as reserve requirements. This real-time market clearing price becomes the settlement price for all internal generators who produced electricity in a given interval. In developing market schedules for each facility to meet forecasted demand, the IESO dispatch algorithm uses the following assumptions: Scheduled intertie transactions cannot exceed the scheduling limits at each interconnection; The change in net intertie transaction schedules from one hour to the next cannot exceed 700 MW; Losses, transmission limits, and area reserve requirements within Ontario are ignored; In real-time, each dispatchable facility can manoeuvre their output at a rate 3 times faster than their submitted ramp rates; and The starting point from which a facility can be dispatched is its schedule from the previous scheduling timeframe. Since market schedules do not consider the physical realities of the transmission system, these results are used for settlement purposes only and do not constitute dispatch instructions to be followed. In real-time, market schedules are calculated every 5 minutes for the previous interval based on the actual market demand within that interval. Constrained Schedules Constrained schedules in pre-dispatch provide advance information which is necessary to plan the physical operations of the electricity system and to allow market participants who own generation facilities to manage their offers to drive their desired operation. In real-time, constrained schedules represent the dispatch targets that must be met by the end of each interval in order to meet the projected market demand in that interval, while respecting the physical characteristics of the transmission system. Ideally, market schedules and constrained schedules will be identical. However, the dispatch algorithm considers the physical characteristics of the transmission system, when determining dispatch instructions, in order to maintain the security and reliability of the IESO-controlled grid. The main influences on constrained schedules are: Generator loss factors on the IESO-controlled grid; April 28, 2011 Public Page 8 of 18

9 Each facility s ability to change its injection or withdrawal from the grid, represented by their submitted ramp rates; Each facility s actual output at the start of the previous interval; Transmission limits based on the design of, and conditions on, the IESO-controlled grid; and Global and area operating reserve requirements. Losses 5 Since transmission lines are not perfect conductors, not all of the electricity produced by a generator will reach the load that must be served. The dispatch algorithm seeks to serve this load at the lowest cost and therefore considers the total amount of generation that must be produced by a given facility to overcome the losses that exist along the transmission path between the generator and the load. For each facility, a static penalty factor is assigned which describes the facility s tendency to increase or reduce transmission system when delivering electricity to a reference point on the transmission system. These penalty factors consider the Richview transformer station in Toronto to be the reference point. A penalty factor greater than 1 means that losses are increased for each MW delivered to Richview. Conversely, a penalty factor less than 1 means that losses are reduced for each MW delivered to Richview. Ramp Rates Ramp rates are used to determine the maximum or minimum output that can be achieved by a facility at the end of the dispatch interval. Unlike the market schedule, the constrained schedule uses each facility s submitted ramp rates to determine dispatch instructions. The constrained schedule uses a real-time telemetry snap shot taken at the start of the current interval and the dispatch target for the current interval to determine the operating point from which the facility will be ramping. Transmission Limits In order to maintain the security and reliability of the IESO-controlled grid, the dispatch algorithm must ensure that constrained schedules respect the physical capabilities and operating limits of the transmission lines and other equipment installed on the transmission system. The IESO utilizes various security analysis tools to ensure that equipment is maintained within these prescribed limits during normal operation as well as in the event of a contingency. Multi-interval Optimization Before the introduction of multi-interval optimization (MIO), resources were dispatched solely based on the expected conditions at the end of the next interval, ignoring conditions in future intervals. MIO allows the dispatch algorithm to optimize dispatch instructions over a number of intervals. It begins by looking at supply and demand in the next interval as well as in four 5 The impact of losses and penalty factors on dispatch will be discussed as part of a future SE-91 stakeholdering discussion, and is out of scope for the Dispatch Technical Working Group. April 28, 2011 Public Page 9 of 18

10 additional critical intervals within the next 55 minutes when determining its dispatch outcome. Through MIO, dispatch instructions are sent for the next interval and dispatch advisories are sent for the additional critical intervals. This allows the dispatch algorithm to achieve a more optimal dispatch of resources with consideration of future needs such as the ability to dispatch a generator to come online earlier than they would otherwise be dispatched in order to make them available for a period of foreseen need. For example, ramping a higher-priced, slowerramping resource now can make additional, lower-cost generation available in a future interval. For further information on how MIO works, a quick-take is available on the IESO website: As part of the dispatchable generation fleet, variable generators will be used by MIO to meet current and future needs. This may involve ramping down variable generators in order to bring on another generator to meet the ramping needs of the system in a future interval. Developing dispatch schedules for variable generators will require knowledge not only of existing output but also their maximum forecasted capability. In today s real-time dispatch process, constrained schedules for variable generators are based on a persistence forecast that assumes that output will remain steady between the time of a telemetry snapshot, taken 5-minutes prior to the dispatch interval, and the end of the dispatch interval. In the absence of an economic or transmission constraint, variable generators will generate per their available fuel conditions. In the event that market or system conditions are such that they receive a dispatch instruction that would reduce their output relative to their available fuel, directly-connected variable generators, or embedded variable generators that are registered market participants, will be expected to follow these dispatch instructions and reduce their output. Once this constraint no longer exists, the variable generator will be able to once again generate per the wind or sunlight conditions. It is expected that some dispatch instructions will be based on persistence forecasting with no expectation of compliance by the generator, allowing generators to maximize their use of available fuel. Others will be developed by the dispatch algorithm, to respect economic or system constraints, which must be followed. Therefore, a mechanism will need to be developed to help variable generators distinguish between these different types of dispatch instructions. Question: If constrained schedules are going to be calculated every 5 minutes for variable generators, but only a subset of these instructions must be followed, how will variable generators be notified for which dispatch instructions they are to comply? Shadow Prices Shadow prices are produced by the dispatch algorithm for information purposes only. They represent the price of energy at every injection and withdrawal point, or node. They are calculated after the determination of constrained schedules and consider the effects of ramp April 28, 2011 Public Page 10 of 18

11 rates, losses and transmission limits. Though they are not used for settlement, they are provided in order to help market participants develop their bid and offer strategies. Shadow prices for each node are published on the IESO website for both pre-dispatch and real-time constrained schedules. Timelines The IESO scheduling and dispatch process runs in three distinct timeframes: day-ahead, predispatch and real-time. Day-Ahead 6 The day-ahead scheduling process is known as the Day-Ahead Commitment Process (DACP). It allows for the commitment of non-quick start generators and imports and provides a 24-hour schedule for all other internal resources within the wholesale electricity market. Generators wishing to operate on a given day must submit dispatch data into the DACP in order to generate in real-time. This dispatch data must be submitted to the IESO before 11:00 EST dayahead. At this time, all standing offers will be converted into dispatch data for use in the DACP. The results of the DACP show pre-dispatch schedules for the rest of the day and for the 24 hours of the next day. Variable generators will receive market and constrained schedules as outputs of the DACP as an advisory of their expected operation in the next day, though there is no financial position associated with a day-ahead schedule. Pre-Dispatch Once the DACP is completed, the pre-dispatch schedules are produced for the remaining hours of the current day and for all hours of the next day. Revisions to existing dispatch data may be submitted with no restrictions up to two hours ahead of the dispatch hour for which the data applies. Within two hours of the dispatch hour, revised dispatch data may be submitted for operator approval provided that it meets certain criteria 7. The pre-dispatch scheduling process provides advance notification of expected operations in future hours for internal resources and the pre-dispatch constrained schedule that is published in the hour immediately preceding the dispatch hour is used to determine the dispatch instructions for intertie transactions. Pre-dispatch also provides the signals to generators when they should synchronize to the IESO-controlled grid and when they should shut down and desynchronize from the grid. Each hourly pre-dispatch run produces the following: Projected market schedules for each facility; Projected dispatch schedules for each facility; 6 Upon the implementation of the Enhanced Day-Ahead Commitment (EDAC) project in Q3 2011, the day-ahead scheduling process will be slightly different. Details on EDAC can be found at 7 These criteria are found in Section 2.1 of Market Manual 4.2: Submission of Dispatch Data in the Real-Time Energy and Operating Reserve Markets, found at April 28, 2011 Public Page 11 of 18

12 Projected market clearing prices; and Projected shadow prices for each node on the ICG. Projected market and dispatch schedules for each facility are available, on a confidential basis to each market participant, through the IESO website. Projected market clearing prices and shadow prices are published publicly on the IESO website. Real-time The real-time dispatch process produces dispatch instructions for each 5-minute interval of the day. These dispatch instructions provide the dispatch target that each dispatchable must reach by the end of the interval to which the instructions relate. Dispatch instructions are sent from the IESO to a participant s dispatch workstation. Dispatch instructions can only be refused for reasons of public or worker safety, equipment damage, or legal requirements. Once accepted, a generator is expected to meet the dispatch instruction by the end of the five-minute interval to which the instruction relates. For each real-time interval, the dispatch algorithm produces the following: Actual market schedules for each facility; Actual dispatch instructions for each facility; Actual market clearing prices; and Actual shadow prices for each node on the ICG. The IESO intends to use existing means of sending dispatch instructions to variable generators. This will require market participants owning variable generation to maintain a dispatch workstation for receiving these instructions. Actual market clearing prices and shadow prices are published publicly on the IESO website. COMPLIANCE Dispatchable generators who receive dispatch instructions must comply with these instructions in order to maintain the reliability of the IESO-controlled grid and efficient operation of the IESO-administered markets. Recognizing that exact compliance is not always possible, the IESO has identified compliance deadbands which depend on the size of the facility. These deadbands are detailed in the IESO Market Rule Interpretation Bulletin, Compliance with Dispatch Instructions to Dispatchable Facilities. 8 For individual resources, the compliance deadbands are as follows: For dispatchable facilities with nominal MW values greater than 30MW, the individual deadband is the greater of ±15 MW or ±2% of the facility s dispatch instruction. For dispatchable facilities with nominal MW values less than 30MW, the individual deadband is ±10 MW. 8 This document can be found at April 28, 2011 Public Page 12 of 18

13 Non-compliance to dispatch instructions outside of the compliance deadband may be a breach of the market rules, unless compliance with the dispatch instruction would endanger the safety of any person, damage equipment, or violate any applicable law. In the event that a market participant cannot operate within their compliance deadband, they are required to notify the IESO. Failure to do so is a breach of the market rules. The design principles approved by SE-91 included a principle relating to the requirement for variable generators to comply with the dispatch instructions that they receive from the IESO. The principle reads as follows: Variable generators will operate within a compliance deadband when ambient conditions offer sufficient fuel. Since the constrained schedules for variable generators will depend on either a persistence forecast of their output or a dispatch instruction driven by an economic or transmission constraint, different compliance treatments will be required when they are operating based upon available fuel conditions and when they have been dispatched down by the IESO. Also, the compliance deadbands for variable generators may be different than those for other dispatchable generators, based on the technical limitations of their generators. Question: Under what conditions will variable generators be held to compliance to their dispatch instructions? What compliance deadbands are appropriate for variable generators? CONGESTION MANAGEMENT SETTLEMENT CREDITS As noted above, a generator s dispatch instructions will ideally be identical to their market schedule. However, this is not always possible because of transmission losses, ramp rates, and transmission limits as described above. When a generator s dispatch instruction is such that they lose an operating profit that they would have realized had they been dispatched according to their market schedule, they are entitled to Congestion Management Settlement Credit (CMSC) payments to keep them whole for this lost operating profit. For the purposes of determining CMSC payments, the market rules assume that each participant offers its resources based on their marginal benefit or cost. Therefore, operating profit for a generator is the difference between operating cost, represented by their offer, and revenue, as represented by the market clearing price. CMSC results from the difference between a generator s expected operating profit under their market schedule and the larger of the operating profit resulting from the dispatch instruction or the operating profit resulting from the actual energy that they produced. Example: A generator offers 100 MW at a price of $20/MW and receives a market schedule for 100 MW and a dispatch instruction to 50 MW resulting from a transmission constraint on the IESO-controlled grid that limited the energy that the generator could supply. The market price in that interval was $25/MW. April 28, 2011 Public Page 13 of 18

14 The generator s operating profit under their market schedule is 100 MW * ($25/MW - $20/MW) = $500 The generator s operating profit resulting from the dispatch instruction (assuming that they produced as dispatched) is 50 MW * ($25/MW - $20/MW) = $250. In this case, the difference between these two operating profits is $250 and the generator would receive a CMSC payment of $250. The design principles approved by SE-91 included a principle relating to the eligibility of variable generators to receive CMSC when their constrained schedule differs from their market schedule. The principle reads as follows: Variable generators will be entitled to Congestion Management Settlement Credit (CMSC) payments. A consideration of what determines a variable generator s operating profit may be warranted since the market and constrained schedules will be defined through a combination of a persistence forecast, maximum forecast availability (possibly provided by the centralized forecaster or the variable facility), and dispatch instructions developed by the dispatch algorithm. Further, CMSC payments should only be made in situations where a variable generator is sent a dispatch instruction which was developed in response to transmission losses, ramp rates or a transmission limit. Question: How will CMSC be calculated for variable generators where differences in operating profit between market schedule and revenue may be driven by factors other than a direct dispatch instruction from the IESO? April 28, 2011 Public Page 14 of 18

15 Next Steps This paper is meant to serve as an education document for variable generators who are unfamiliar with the IESO dispatch process. It is also intended to highlight some of questions that will need to be resolved as the IESO moves forward to integrate variable generation into its dispatch algorithm. To this end, the IESO will be creating a Dispatch Technical Working Group, under the Renewable Integration (SE-91) stakeholder engagement, to discuss these and other issues with stakeholders. Stakeholders interested in participating in this effort are encouraged to refer to the Renewable Integration stakeholder engagement page on the IESO website: to see the terms of reference and membership application processes. April 28, 2011 Public Page 15 of 18

16 Appendix A Renewable Integration Design Principles Forecasting: Principle 1: The IESO will implement a centralized forecast for all wind and solar resources with an installed capacity of 5MW or greater and all wind and solar resources directly connected to the IESO Controlled Grid. Principle 2: Real-time forecast data will be used for variable generation dispatch and actual real-time data will be used for calculating foregone energy to support OPA contract settlement. Principle 3: The costs paid to the centralized forecast service providers will be treated as procured service charges and will be recovered from consumers through existing procurement market recovery mechanisms. Visibility: Principle 4: All variable resources subject to centralized forecasting will provide static plant information and data. Principle 5: All variable resources subject to centralized forecasting will provide dynamic data (real-time telemetry). Principle 6: All forecasts of facility output for resources subject to centralized forecasting will be publicly available. Dispatch: Principle 7: All variable resources connected to the IESO-Controlled Grid, and embedded variable resources that are registered market participants, will be actively dispatched on a five-minute economic basis. Principle 8: Variable generators will operate within a compliance deadband when ambient conditions offer sufficient fuel. April 28, 2011 Public Page 16 of 18

17 Principle 9: Variable generators will be entitled to Congestion Management Settlement Credit (CMSC) payments. Principle 10: The IESO may establish various floor prices for offers from baseload generators (e.g. wind, must-run hydro, nuclear, etc.) to ensure efficient dispatches during periods of local and/or global surplus baseload generation (SBG) events. Principle 11: Directly connected variable resources (and embedded resources that are market participants) will be eligible to participate in Operating Reserve and ancillary markets where technically feasible (such integration will be considered on a cost benefit basis, and is not likely to be addressed in the near term). April 28, 2011 Public Page 17 of 18

18 Appendix B Discussion Questions The following is a consolidated list of the questions raised in the discussion paper: 1. What technical limitations exist for wind and solar generators that must be respected by the dispatch algorithm in order to produce a viable dispatch instruction that can be followed? 2. Do wind and solar generators require the use of all 20 price/quantity pairs? Are two price/quantity pairs sufficient to capture their price sensitivity over their operating range? 3. Do wind and solar generators require the ability to submit ramp rates and break points? Should the IESO assume a common ramp rate for variable generators as dictated by their fuel type? 4. If constrained schedules are going to be calculated every 5 minutes for variable generators, but only a subset of these instructions must be followed, how will variable generators be notified for which dispatch instructions they are to comply? 5. Under what conditions will variable generators be held to compliance to their dispatch instructions? What compliance deadbands are appropriate for variable generators? 6. How will CMSC be calculated for variable generators where differences in operating profit between market schedule and revenue may be driven by factors other than a direct dispatch instruction from the IESO? April 28, 2011 Public Page 18 of 18

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