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RC Meeting August 4, 2009 Marianne Perben Senior Engineer, FCM & Tariff Administration

Forward Capacity Market (FCM) Reliability Reviews Related Issues Follow-up Discussion. RC Meeting August 4, 2009 Marianne Perben Senior Engineer, FCM & Tariff Administration. Background.

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RC Meeting August 4, 2009 Marianne Perben Senior Engineer, FCM & Tariff Administration

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  1. Forward Capacity Market (FCM) Reliability Reviews Related Issues Follow-up Discussion RC Meeting August 4, 2009 Marianne Perben Senior Engineer, FCM & Tariff Administration

  2. Background • At the 07/13/09 Reliability Committee (RC) meeting, discussion was held that focused on the second item of the Issues List: 2) Reliability Reviews Related Issues • For the purpose of this discussion, the reliability reviews under consideration included annual reliability reviews performed by ISO System Planning for the Forward Capacity Auctions, Annual Reconfiguration Auctions and annual bilateral transactions • As part of the discussion, to ensure consistency and transparency, assumptions related to annual reliability reviews were also compared to assumptions related to the analyses performed by ISO System Planning to set the system Installed Capacity Requirements (ICR) and local sourcing requirements (LSR/MCL) • A presentation on Reliability Reviews Related Issues and an accompanying matrix described the preliminary ISO position

  3. Purpose of Today’s Discussion • Review commented items from the 07/13/09 discussion • Use of potentially different assumptions in the calculation of ICR, LSR and MCL and the performance of annual reliability reviews • Use of the 90/10 load forecast • De-rating of generation by an ambient air de-rate • Reliance on load relief from OP-4 actions • Present additional details regarding peaking generation resources forced outage assumptions • Present revised assumptions matrix

  4. Input Assumptions • Input assumptions relevant to the annual reliability reviews include assumptions related to all elements of the power system • Load, resources, transmission topology, transmission transfer capability and operating/emergency actions • The choice of a specific assumption over another should be based on careful consideration of the following three elements • Purpose of the analysis and necessity for consistency with other analyses • Study time frame and potential risk aversion • Type of analysis and tools used to perform the analysis (deterministic vs. probabilistic)

  5. Consistency Discussion • Should the same assumptions used for calculating the ICR, LSR and MCL be used for reliability reviews? • The calculation of ICR, LSR and MCL is purely based on resource adequacy requirements and is done using probabilistic tools • The performance of reliability reviews is purely based on transmission security requirements and is done using deterministic tools • Per NPCC Document A-2, resource adequacy and transmission security requirements are both necessary to meet basic reliability requirements • They are like food and water; they do not suffice by themselves • They meet different, yet complementary purposes, one being to ensure resource adequacy, the other being to ensure transmission security • Keeping assumptions between both analyses identical may not necessarily achieve the intended resource adequacy or transmission security analyses objectives

  6. Load forecast in Annual Reliability Reviews • At the 07/13/09 meeting, the ISO recommended using the 90/10 load forecast for annual reliability reviews • The 90/10 load forecast corresponds to peak loads that have a 10% chance of being exceeded due to weather variations (and not due to long term regional economic/demographic forecast variations) • Resource adequacy analyses are performed using the full probability distribution of load variations due to weather uncertainty • This includes the 0.01/99.99 load forecast as well as the 99.99/0.01 load forecast • For the purpose of performing deterministic transmission security analyses, a single discreet point on the probability distribution has to be chosen • The ISO continues recommending using the 90/10 forecast for annual reliability reviews • Reaching or exceeding the 90/10 forecast has occurred in the past (most recently in the summer of 2001 and 2006) and will occur again in the future • Using the 90/10 forecast is consistent with the risk associated with the time frame of Planning analyses and the way other Transmission Planning analyses are performed

  7. De-rating of Generation by an Ambient Air De-rate • On 07/13/09, ISO proposed to de-rate regular and peaking generation resources by an ambient air de-rate • This proposal was related to the fact that deterministic transmission security analyses are performed at 90/10 load • The 90/10 load is the peak load that has a 10% chance of being exceeded and is expected to occur at a weighted New England-wide temperature of 94.2°F • This temperature is different from the 90°F reference temperature used to establish a resource’s summer seasonal claimed capability • Since, several concerns were raised related to this proposal • How would the un-uniform nature of temperatures across New England be taken into account in the application of this ambient air de-rate? • Wouldn’t some double-counting occur if the ambient air de-rate is already reflected in the resource’s EFORd? • How would this ambient air de-rate be accounted for in the case of resources with accepted de-list bids for ambient air de-rate? • The ISO will not apply the ambient air de-rate at this point in time

  8. Definition of Peaking Generation • In-service resources are classified as peaking generation resources if they are non-hydro resources and satisfy Market Rule 1 definition of a Fast Start Generator • “Fast Start Generator” shall mean a generating unit that the ISO may dispatch within the hour through electronic dispatch and that meets the following criteria: (i) minimum run time does not exceed one hour; (ii) minimum down time does not exceed one hour; (iii) time to start does not exceed 30 minutes; (iv) available for dispatch and manned or has automatic remote dispatch capability; (v) capable of receiving and acknowledging a start-up or shut-down dispatch instruction electronically; and (vi) has satisfied its minimum down time. • New resources are classified as peaking generation resources if they are diesels, gas turbines or jet engines 8

  9. Peaking Generation Forced Outage Assumptions in Annual Reliability Reviews • Background • The ISO is concerned about using traditional statistical measures (EFORd) for peaking generation forced outage assumptions in transmission security analyses • Traditional statistical measures do not capture the ability of a peaking generator to start and remain on-line • Traditional statistical measures tend to be positively biased for low capacity factor generators (such as peaking generators) • Capturing such starting ability is key to assess the ability of the system to be secured in 10 or 30 minutes in transmission security analyses • Based on operational experience, past deterministic analyses have been performed using a 33% forced outage factor 9

  10. Peaking Generation Forced Outage Assumptions in Annual Reliability Reviews, cont. • As a potential alternative to the 33% forced outage factor, the ISO recently researched the use of a statistical measure that would adequately capture the ability of a peaking generator to start and remain on-line, even if infrequently called upon • The ISO reviewed the use of the Utilization Forced Outage Probability (UFOP) • UFOP needs a drastically augmented data collection process to be implemented in New England • As another alternative the ISO considered the application of a deterministic adjustment factor • Would reflect the potential for some peaking generation not starting or starting and stalling, without broadly relying on a high forced outage factor • Consists in outaging a discreet number of peaking generators among the fleet of peaking generators used in a reliability area; several alternatives are considered • Outage the most impacting unit • Outage the two most impacting units • Outage one unit per station • Outage the most impacting unit out of five, not exceeding one per station 10

  11. Reliance on OP-4 Actions in Annual Reliability Reviews • Background • Annual reliability reviews performed in the past generally did not rely on load relief from implementing OP-4 actions • Changes to OP-4 are now being implemented to integrate the new FCM demand products into the ISO Operating Procedures • Access to active demand resources that are purchased under FCM now occurs concurrently with OP-4 actions • In order to capture all resources that are purchased under FCM, the ISO is proposing to reflect some load relief from certain OP-4 actions in the annual reliability reviews • This includes reliance on all Active Demand Resources (Real-Time Demand Resources and Real-Time Emergency Resources) • It does not include reliance on any other load relief from OP-4 actions • Consistency with the risk associated with the time frame of Planning analyses • Leave some “tools” in the Operators’ “tool box” 11

  12. Reliance on OP-4 Actions in Annual Reliability Reviews, cont. • The ISO is not proposing to rely on Control Area-to-Control Area Emergency Transactions in the annual reliability reviews • Relying on these Emergency Transactions would be inconsistent with NPCC Document A-2 and Planning Procedure No. 3 which call for modeling applicable transfers that reasonably stress the system • Transmission security analyses model a range of transfer conditions that reasonably stress the system, one of which is represented by 0 MW transfers on the external ties • Modeling these Emergency Transactions as part of the annual reliability reviews would result in the potential acceptance of a de-list bid, based on the assumptions that the Emergency Transactions will always be delivered to New England at times of peak, regardless of the state of the transmission system and capacity level in the external control area 12

  13. Conclusions The attached version of the assumptions matrix summarizes the ISO’s current position regarding assumptions to be used in annual reliability reviews The ISO believes that these assumptions are consistent with the basic reliability requirements set in NPCC Document A-2 and New England Planning Procedure No. 3 and with the intent of the Forward Capacity Market The ISO is planning on finalizing these assumptions at the 08/17/09 RC meeting

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