Draft Minutes for Comment
NEPOOL Power Supply Planning Committee (PSPC)
Meeting No. 310
January 15, 2015
ISO New England Offices
Holyoke, MA
Attendee Name / AffiliationPete Aufdemorte / United Illuminating
Tom Bessette / MA DPU
Cal Bowie* / Eversource Energy
David Burnham* / NU
Margo Caley / ISO New England Inc.
Dorothy Capra* / NESCOE
Simmi Chaudhury / ISO New England Inc.
Quan Chen / ISO New England Inc.
David Ehrlich / ISO New England Inc.
Dave Errichetti / Eversource Energy
Bill Fowler* / Sigma Consulting
Mike Harrington / NH PUC
Ron Hart* / Dominion
Tom Kaslow / GDF SUEZ Energy Marketing North America, Inc.
Abby Krich* / Boreas Renewables
Paul Lopes* / State of MA Division of Energy Resources
Jim Hyland* / MMWEC
Bill Killgoar* / Long Island Power Authority
Boris Koropey / NH PUC
Ed McNamara / VT Public Service Department
Bruce McKinnon / CMEEC
Fred Plett / MA Attorney General’s Office
Jose Rotger* / ESAI for Cross-Sound Cable and Emera Energy
Eric Runge* / Day Pitney
Maria Scibelli (Secretary) / ISO New England Inc.
Doug Smith / ISO New England Inc.
Eric Winkler / ISO New England Inc.
Sharon Weber* / PPL
Peter Wong (Chair) / ISO New England Inc.
Fei Zeng / ISO New England Inc.
* Indicates attendance by phone
1. Chair Report
1.1 Chair Report [slides]
Mr. Peter Wong welcomed the Committee. He reported that FERC issued an order on January 2, 2015 to accept the Installed Capacity Requirement (ICR) and Related Values for the 9th Forward Capacity Auction (FCA). He noted that a spreadsheet of historical ICR and Related Values entitled “Summary of ICR, LSR & MCL for FCM and the Transition Period” is updated and available on the ISO website.
Mr. Wong shared ways to be informed of meeting cancellations, especially due to inclement weather.
At the next meeting, ISO New England (ISO) will present to the PSPC on results of the Loss of Load Expectation (LOLE) simulations to identify the number of times different actions of the ISO Operating Procedure No. 4 (OP4), Actions During a Capacity Deficiency may be invoked at different installed capacity levels.
1.2 Draft Minutes
Ms. Scibelli reported that the draft minutes for PSPC Meetings No. 305, 306, and 307 were posted and comments were received from Mr. Tom Kaslow and Mr. Bruce McKinnon. The minutes were accepted as final with the aforementioned changes incorporated.
2. 2015 ICR Calculations
2.1 2015 ICR Development Schedule [slides]
Ms. Scibelli gave an overview of the 2015 ICR development schedule, which includes calculating ICR and related values for the 2019/20 FCA(FCA10), 2018/19 1st Annual Reconfiguration Auction (ARA) (ARA1), 2017/18 ARA2, 2016 /17 ARA3, and representative values for the Regional System Plan (RSP) and resource adequacy studies.
Mr. Wong noted that FCA10 import and export constrained Capacity Zones are being developed and will be finalized within the next few months. Final FCA10 Capacity Zone determinations will be reviewed at the June PSPC meeting, followed by a review of tie benefits at the July meeting.
2.2 Status Report Regarding PV Assumptions for the 2019/20 (FCA10) ICR Calculation [slides]
Mr. Wong provided a status report on the ISO assessment regarding incorporating Photovoltaic (PV) resources in FCA10 ICR calculations. He gave a description of the four types of PV resources in New England and which type of PV the ISO is planning to incorporate into the load forecast. The ISO is assessing methodology for adding Behind the Meter Not Embedded in Load (BTMNEL) PV resources to FCA10 ICR calculations by capturing and adjusting the load forecast to account for this type of PV.
Q – Mr. Errichetti – On slide 4, do settlement only generating resources (SOR) currently include PV resources?
A – SOR do include PV resources. Also, some PV may participate in FCM and have a Capacity Supply Obligation (CSO).
Q – Mr. Errichetti – Is there SOR generation included in the calculation of hourly loads? They impact the ICR calculation in that they don’t mask load.
A – The load in New England is calculated as generation energy plus the net energy imports minus net energy exports so SOR are included within the load.
Q – Mr. Errichetti – When the ICR model is developed, will SOR discussed on slide 5 be intentionally ignored?
A – SOR are not included as a supply resource in FCM. Any resource without a CSO is not included in ICR calculations per current Market Rules.
Q – Mr. McKinnon–Stated that SORs are not behind the meter.
A – They are fully metered, net energy generators; what generation remains after serving own load is metered.
Q – Mr. McKinnon– On slide 5 pertaining to SOR, what does “may or may not have generator characteristics” mean?
A – SOR are not dispatched by the ISO control room. These units are generally less than 5 MW.
Q – Mr. Rotger– On slide 5, do these SORs have CSOs?
A – These SORs differ from intermittent generator resources participating in FCM. They do not have CSOs unlike FCM intermittent generators, which are expected to run and subject to penalty during shortage event hours. These SORs are energy only resources.
Q – Mr. Lopes– What is preventing PV from enrolling into FCM?
A –. As long as the owners/aggregators of the PV have capacity transmission rights and are a NEPOOL participant, they can submit a resource qualification package to the ISO to participate in FCM.
Q – Mr. Kaslow– Where does the information on slide 6 about behind the meter PV installations come from?
A – The information is from state agencies.
Q – Ms. Krich – What is the difference between type 2 and 4 of PV resource types?
A – Type 2 are energy only resources not obligated to perform during FCM shortage hours. They are not relied upon for reliability and cannot be counted in ICR calculations as defined in the ISO Market Rules. Type 4 is the BTMNEL (consisting of mostly residential roof top installations) which the PV forecast is trying to address.
Q – Ms. Krich– Does including type 4 resources require a tariff change?
A – After ISO assessment it was determined that this falls under the load forecast methodology and including PV that is not already embedded in the load forecast does not need to be addressed with Market Rule changes. This can be accomplished for FCA10.
Q – Ms. Krich– What cannot be accomplished by FCA10?
A – Anything requiring Market Rule changes will need additional stakeholder process and voting. There is not enough time to implement those changes in FCA10. Certain ICR and FCM assumptions will need to be finalized by March/April timeframe.
Q –The PSPC asked for clarification if this analysis is an actual forecast of PV resources for future years.
A – The PV forecast is a ten-year forecast future of installation of PV resources. It is based on the ratio of current installations of SOR and Behind the Meter (BTM) PV resources accounted for in the load forecast. The PV forecast is being incorporated into the load forecast for FCA10 since there is expected to be hundreds of MW of PV growth between now and 2019. It is expected growth in PV will stabilize once states reach their penetration goals.
Q – Mr. Kaslow – The FERC order directed ISO to investigate distributed generation (DG). When will other types of DG in addition to PV be addressed?
A – ISO is focusing on PV right now. PV data is available from the states since they are tracking Renewable Energy Credits (RECs).
Mr. Kaslow wished to have a NEPOOL Committee interpretation of the FERC order and stated that the Planning Advisory Committee (PAC), a non-NEPOOL committee, is not the correct venue.
Q – Mr. Errichetti – Asked for the amount of SOR that do not have CSOs and are thus excluded from ICR models. He expects this will be any generator with a Seasonal Claimed Capability (SCC) value that does not have a CSO.
A – Mr. Wong will provide this.
Q – Mr. McKinnon – Asked why PV is not included in the ICR model when Energy Efficiency (EE) is included and it is also non-dispatchable.
A – Mr. Wong stated that when the FCM was created, the settlement agreement allowed EE to be a market resource as part of a negotiated outcome. If PV is to be the same, it would require a committee process and Market Rule changes. Mr. McKinnon asked to note his observation that PV is more like EE than it is like generating resources and thus, may require the same treatment as EE.
Q – Mr. McKinnon – Regarding comments that BTMNEL PV installations would decline over time; there could be new technologies that would change this.
A – Mr. Wong advised PSPC members to attend future PAC and Distributed Generation Forecast Working Group (DGFWG) meetings.
3. Topics Relating to Capacity Demand Curves
3.1 Tie Benefits Study Assuming Various LOLE Levels Additional Results [slides]
Mr. Wong presented on the total amount of tie benefits available from neighboring areas while assuming New England and neighboring areas at certain Loss of Load Expectation (LOLE) levels. The results are provided as information and not a prediction of the FCA9 outcome.
Q – Mr. McKinnon– On slide 6, there is a cause for concern, as there is a 25% increase in reliance on ties, in aggregate. What is the impact on various interfaces? Where would New England get assistance for an additional 450 MW of tie benefits above what was included in the ICR calculation?
A – These questions and evaluating the impacts are part of current ISO efforts.
Q – Mr. Rotger – In light of the lack of recent shortage events, with the exception of December 2014, are specific external control areas available to supply assistance more readily than others, and are there ways to determine that?
A – The study assumed Quebec and Maritimes at 1 in 10, which is their planning criterion. The December shortage event was caused by equipment tampering in Quebec which caused curtailment of exports to New England and is not related to resources adequacy. ISO is conducting this analysis due to a lack of historical data.
Q – Mr. Rotger asked if the amount of resources needed to bring New England back to 1 day in 10 years LOLE when isolated could be determined.
A – Mr. Wong will provide this information at the February PSPC meeting.
Q –Ms Krisch – Does the isolated New England system include capacity imports?
A – There are 89 MWs of Existing capacity imports included.
3.2 New England Operable Capacity Margins at Different Assumed Installed Capacity Levels [link]
Mr. Wong presented on a study that identified the New England operable capacity margins at different assumed installed capacity levels for the 2018/19 Capacity Commitment Period (CCP) using the FCA9 ICR assumptions.
Q - Mr. McKinnon – Why is the current reserve requirement of 125% of the largest contingency used as an assumption for calculating future operating reserve requirements when this was supposed to be temporary?
A - The previous requirement was increased to 125% more than a year ago to ensure system reliability in response to contingencies and this requirement is still being enforced. The ISO will keep the PSPC updated if there are any changes to the requirement.
4. Representative ICR Values – PAC Presentation [link]
Ms. Scibelli presented the Future Representative Installed Capacity Requirements for 2019/20 – 2023/24. She informed the PSPC that the Transmission Security Analysis (TSA) Requirements forecast is not yet available, but will be included in the PAC presentation at their January 21, 2015 meeting. The representative values are calculated the same way as ICR, using FCA9 resource assumptions and 2014 CELT load forecast.
Q – Mr. Rotger – Are the representative values presented included in the 2015 Regional System Plan (RSP15)?
A – RSP15 will include an indicative style analysis of an average reserve margin multiplied times the 50/50 peak load forecast. The information presented today should be considered as an addendum to RSP14.
Q – Mr. Errichetti – How is a 14.2% reserve margin calculated for use in the RSP15 forecast?
A – The 14.2% is the average resulting reserve margin of certain recent calculations of ICR for FCM and that choosing different ICRs can change the average reserve margin used in the forecast.
Q – Ms. Krich – How is the 13.9% for 2018/19 related to the 14.2% reserve margin forecast?
A – The 13.9% was FCA9’s resulting reserve margin and was calculated after the average 14.2% reserve margin was used in RSP14. The 14.2% was calculated based on recent FCA ICR resulting reserve margins calculated prior to FCA9.
Q – Ms. Krich – What is the size of the proxy unit?
A – The proxy unit is 400 MW. FCA9 required 4 proxy units for 1 in 10 LOLE, 1 unit for 1 in 5 LOLE and 11 units for the 1 in 87 LOLE ICR models.
Q – Mr. Bowie –Why is Connecticut’s but not Maine’s future local requirements calculated in this presentation? Capacity Zones for 2019/20 could be different from zones determined for FCA9.
A – Assumptions are based on FCA9 system topology and held constant throughout the forecast period. While it is true the system could be completely different in the future, this represents our most recent knowledge of the system.
Q – Mr. Errichetti – In the Local Resource Adequacy (LRA) Requirements study, are proxy units put in rest of pool?