ISO-NE PUBLIC
A G E N D A I T E M 3 . 2 , 3 . 3 | P S P C M E E T I N G N O . 3 2 7
A U G U S T 1 7 , 2 0 1 7
Manasa Kotha
• 2018-2019 Third Annual Reconfiguration Auction (2018-2019 ARA 3) • 2019-2020 Second Annual Reconfiguration Auction (2019-2020 ARA 2) • 2020-2021 First Annual Reconfiguration Auction (2020-2021 ARA 1)
Assumptions for the Installed Capacity Requirement (ICR) Values Calculations
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Objective of this Presentation
• Review the ICR Values* development, NEPOOL committee review and FERC filing schedules for Annual Reconfiguration Auctions (ARAs) for Capacity Commitment Period (CCP) 2018-2019 through CCP 2020-2021
• Review the assumptions for calculating: – Installed Capacity Requirement (ICR) – Transmission Security Analysis (TSA) – Local Resource Adequacy Requirement (LRA) – Local Sourcing Requirement (LSR) – Maximum Capacity Limit (MCL) – System/Zonal(as applicable)Demand Curves requirement values
*The ICR, LSR, MCL and Demand Curve values are collectively referred to as the ICR Values
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ICR Values Schedule
• CCP 2018-2019 ARA 3 – Mar 1, 2018
• CCP 2019-2020 ARA 2 – Aug 1, 2018
• CCP 2020-2021 ARA 1 – Jun 5, 2018
– PSPC final review of all assumptions – Aug 17, 2017
– PSPC review of ISO recommendation of ICR Values – Sep 25, 2017
– RC review/vote of ISO recommendation of ICR Values – Oct 17, 2017
– PC review/vote of ISO recommendation of ICR Values – Nov 3, 2017
– File with FERC – by Dec 1, 2017
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ICR Values for the following ARAs will be calculated, reviewed and filed concurrently:
ISO-NE PUBLIC
Calculation of ICR Values
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LSR, MCL and Demand Curve capacity requirement values will be calculated for the same Capacity Zones determined for the respective Forward Capacity Auction (FCA)
CCP 2018-2019 CCP 2019-2020 CCP 2020-2021
Import Capacity Zone (LSR, LRA,TSA)
Connecticut NEMA-Boston
SEMA-RI
Southeast New England (SEMA, RI, NEMA-Boston)
Southeast New England (SEMA, RI, NEMA-
Boston)
Export Capacity Zone (MCL)
- - Northern New England
(ME, NH,VT)
Demand Curves
System-Wide Capacity Demand Curve
Cap at 1-in-5 LOLE capacity requirement, $17.728/kW-
month
Foot at 1-in-87 LOLE capacity requirement, $0/kW-month
System-Wide Capacity Demand Curve
Cap at 1-in-5 LOLE capacity
requirement, $17.296/kW-month
Foot at 1-in-87 LOLE capacity requirement, $0/kW-month
Marginal Reliability Impact (MRI) Curves
System-wide
Zonal
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ASSUMPTIONS FOR THE CCP 2018-2019 ARA 3, CCP 2019-2020 ARA 2 AND CCP 2020-2021 ARA 1
ICR VALUES CALCULATION
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Modeling the New England Control Area
The New England ICR is calculated using the GE MARS model – Internal transmission constraints are not modeled. All loads and
resources are assumed to be connected to a single electric bus
– Internal transmission constraints are addressed through LSR and MCL
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Assumptions for the ICR Values Calculations
• Load Forecast – Net of behind the meter (BTM) photovoltaic (PV) resource forecast
– Load forecast distribution
• Qualified Capacity (QC) of resources* – Generating Capacity Resources
– Intermittent Power Resources (IPR)
– Import Capacity Resources
– Demand Resources (DR)
• Resource availability – Generating Resources’ availability
– Intermittent Power Resources’ availability
– Demand Resources’ availability
• Load relief from OP 4 actions – Tie reliability benefits
• Quebec (includes HQICCs)
• Maritimes
• New York
– 5% voltage reduction
* Known resource retirements are removed; new cleared capacity resources are added as applicable; capacity imports are derated
.
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Load Forecast Data
• Load forecast assumption from the 2017 Capacity, Energy, Loads and Transmission(CELT) Report Load Forecast
• The load forecast weather related uncertainty is represented by specifying a series of multipliers on the peak load and the associated probabilities of each load level occurring – derived from the 52 weekly peak load distributions described by the
expected value (mean), the standard deviation and the skewness
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Modeling of BTM-PV in ICR Values Calculations (MW)
Notes: *For more info on the PV forecast, see https://www.iso-ne.com/static-assets/documents/2017/05/2017_solar_forecast_details_final.pdf
• The ARAs’ ICR probabilistic calculations use an hourly profile of BTM PV corresponding to the load shape for the year 2002, used by the Northeast Power Coordinating Council (NPCC) for reliability studies. For more information on the development of the hourly profile see: https://www.iso-ne.com/static-assets/documents/2017/06/pspc_6_22_2017_2002_PV_profile.pdf
– used for all probabilistic ICR Values calculations – modeled in GE MARS by Regional System Plan (RSP) 13-subarea representation – includes an 8% Transmission & Distribution Gross-up
• The values of BTM PV published in the 2017 CELT Report are the values of BTM PV subtracted from the Gross Load Forecast to determine the Net Load Forecast
– developed using the estimated peak load reduction percent of PV nameplate forecast from the Distributed Generation Forecast Working Group (DGFWG)
– 2018-2019 = 36%; 2019-2020 = 34.6%; 2020-2021 = 33.5%*
• In the TSA, the published 90/10 Net Load Forecast for the appropriate import-constrained sub-areas for each Capacity Zone is used
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Load Forecast (MW) For Applicable Capacity Zones and Total New England
• 50/50 & 90/10 load forecasts values are from the 2017CELT Report’s load forecast (labeled “1.2
REFERENCE - With reduction for BTM PV”) for the corresponding RSP sub-areas used in the ARA ICR Values calculations
• The Reference 50/50 load forecast shown is for informational purposes; in the ICR Values calculations, the GE MARS model sees an hourly distribution of loads with the BTM PV modeled in an hourly profile
• The 90/10 load forecast values are used directly in the calculation of TSA for import-constrained Capacity Zones; all other values shown are for informational purposes
Boston CT SEMA-RI SENE NNE Total New England
CCP 50/50 90/10 50/50 90/10 50/50 90/10 50/50 90/10 50/50 90/10 50/50 90/10
2018-2019 6,174 6,651 7,320 7,993 5,778 6,332 28,764 31,183
2019-2020 12,076 13,125 28,970 31,426
2020-2021 12,202 13,269 5,668 6,069 29,191 31,683
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Resources’ QC Resource Data : Used the latest available data for each CCP
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Note: *Qualified New Capacity Resources on critical path schedule monitoring with deliverability prior to June 1st 2020
2018-2019 ARA 3 2019-2020 ARA 2 2020-2021 ARA 1
2018-2019 ARA 2 bilateral period QC
data
2019-2020 ARA 1 QC Capacity data
2020-2021FCA existing QC data + 2020-2021 FCA New Capacity
Resources amount*
Import Capacity Resources • The QC values are de-rated if the sum of the import QC is higher than the remaining
Transmission Transfer Capability (TTC) of the external interface after accounting for tie benefits
• This is the same procedure used for the ARA ICR calculations in previous years
Demand Resources
• Conversion of Real-Time Emergency Generation (RTEG) resources into Real-Time Demand Response (RTDR) resources is reflected for ARA 2 for CCP 2019-2020 and ARA 1 for CCP 2020-2021
• For ARA 3 for CCP 2018-2019 the Qualified Capacity of RTEG Resources is zero
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Resources’ QC By Capacity Zone & Total New England
2018-2019 ARA 3
2019-2020 ARA 2
2020-2021 ARA 1
Note: • Generating resources include a 30 MW derating to reflect the value of the firm Vermont Joint Owners (VJO) contract • Known Non-Price Retirement requests are removed from the applicable CCP
Resource Type NEMA-Boston Connecticut SEMA-RI New England
Non-Intermittent Generating Resources 3,261 9,200 6,656 30,074
Intermittent Generating Resources 79 171 112 1,073
Import Capacity Resources - - - 1,730
Demand Resources-On Peak 596 82 520 1,904
Demand Resources-Seasonal Peak - 459 - 511
Demand Resources-Real Time 128 102 107 620
Total 4,063 10,012 7,395 35,913
Resource Type SENE New England
Non-Intermittent Generating Resources 9,689 30,336
Intermittent Generating Resources 190 1,017
Import Capacity Resources - 1,510
Demand Resources-On Peak 1,245 2,103
Demand Resources-Seasonal Peak - 509
Demand Resources-Real Time 207 781
Total 11,331 36,255
Resource Type NNE SENE New England
Non-Intermittent Generating Resources 7,286 10,056 30,878
Intermittent Generating Resources 464 188 912
Import Capacity Resources 255 - 1,235
Demand Resources-On Peak 383 1,440 2,313
Demand Resources-Seasonal Peak - - 596
Demand Resources-Real Time 245 200 765
Total 8,632 11,884 36,700
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Internal TTC Assumptions (MW) -For LSR and MCL Modeling
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Notes: • Transmission transfer capability limits – presented at the Planning Advisory Committee (PAC) on March 22, 2017
(CEII)
Boston Import (for NEMA-Boston
LSR) Connecticut Import
(for Connecticut LSR) SEMA-RI Import
(for SEMA-RI LSR)
Southeast New England Import (for SENE LSR)
North-South Interface (for NNE
MCL)
CCP N-1 N-1-1 N-1 N-1-1 N-1 N-1-1 N-1 N-1-1 N-1
2018-2019 4,850
4,175 2,950
1,750 1,280
720
2019-2020 5,700
4,600
2020-2021 5,700
4,600
2,725
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Proxy Unit Characteristics
• Proxy unit characteristics based on a study conducted in 2014 using the CCP 2017-2018 FCA #8 ICR model
• Current proxy unit characteristics: – Proxy unit size equal to 400 MW – EFORd of proxy unit = 5.47% – Maintenance requirement = 4 weeks
0.0200
0.0250
0.0300
0.0350
0.0400
100 150 200 250 300 350 400 450
LOLE
(Day
s/Ye
ar)
Proxy Unit Size (MW)
LOLE @ Proxy Unit Size FCA8 Model LOLE (0.0296)
Point where proxy unit characteristics achieve system LOLE
Notes:
• The 2014 Proxy Unit Study was reviewed at the May 22, 2014 PSPC Meeting and is available at: http://www.iso-ne.com/static-assets/documents/committees/comm_wkgrps/relblty_comm/pwrsuppln_comm/mtrls/2014/may222014/proxy_unit_2014_study.pdf
• Proxy unit characteristics are determined using the average system availability and a series of LOLE calculations. By replacing all system capacity with the correct sized proxy units, the system LOLE and resulting capacity requirement remain unchanged
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Resource Availability Assumptions Generating Resources
• Forced outages assumption – Each generating unit’s Equivalent Forced Outage Rate on (non-weighted
EFORd) modeled – Based on a 5-year average (Jan 2012 – Dec 2016) of generating unit data
submitted to Generation Availability Data System (GADS) – NERC GADS Class average data is used for immature & non-commercial units
• Scheduled outage assumption – Each generating unit’s weeks of maintenance modeled – Based on a 5-year average (Jan 2012 – Dec 2016) of each generating unit’s
actual historical average of planned and maintenance outages scheduled at least 14 days in advance
– NERC GADS Class average data is used for immature & non-commercial units
• Each CCP will have the appropriate generating units modeled along with their individual availability statistics
• Intermittent Power Resources are modeled as 100% available since their outages have been incorporated in their 5-year historical output used in their ratings determination
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Resource Availability Assumptions, Contd. Demand Resources (DR)
– Uses historical DR performance from summer & winter 2012 – 2016 (same values developed for FCA #12)
For more information see the May 2017 PSPC presentation
https://www.iso-ne.com/static-assets/documents/2017/05/a3_pspc_2017_dr_availability_for_icr_05182017.pdf
– Modeled by zones and type of DR with outage factor calculated as 1- performance/100
– The same performance values will be applied for CCP 2018-2019 through CCP 2020-2021
Import Capacity Resources
– Modeled in the ICR calculations as: • Pool backed are 100% available
• Resource backed are modeled with availability assumptions show below
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NERC Class Average EFORd % Maintenance
(Weeks) HYDRO 30 Plus 3.49 6.77
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Resource Availability Assumptions, Contd.
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EFORd Assumption for Non-Commercial Large Combustion Turbines (CTs)
• ISO-NE requested a Class Average value from NERC for CTs greater than 200 MW and greater than 300 MW – NERC was not able to provide a value for CTs greater than 300 MW
since too few units report in that category to maintain confidentiality – 2011 - 2015 five-year average EFORd for units greater than 200 MW is
4.69% (received this data from NERC in February 2017) – For the five-year period there were, on average, 26 units reporting
with an average age of 9 years – ISO-NE is using the 4.69% NERC Class Average EFORd assumption
value for CTs greater than 200 MW (currently only applies to Canal 3)
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Resource Availability Assumptions, Contd.
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Note:
• Non-Intermittent Generating Resources uses the same per unit EFORd and maintenance weeks values developed for FCA #12. In the LOLE simulations, individual unit values are modeled
• Assumed summer MW weighted EFORd/Forced Outage Rate (FOR) and maintenance weeks are shown by resource category for informational purposes
• Non-Intermittent Generating resources category includes a 30 MW derating to reflect the value of the firm VJO contract
Resource Type Summer MW
Assumed Average EFORd/Forced Outage Rate (%) Weighted by
Summer Ratings
Assumed Average Maintenance Weeks
Weighted by Summer Ratings
Non-Intermittent Generating Resources 30,074 7.6 4.7
Intermittent Generating Resources 1,073 0.0 0.0
Import Capacity Resources 1,730 2.0 4.5
Demand Resources-On Peak 1,904 0.0 0.0
Demand Resources-Seasonal Peak 511 0.0 0.0
Demand Resources-Real Time 620 9.9 0.0
Total New England 35,913 6.6 4.1
CCP 2018-2019 ARA 3
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Resource Availability Assumptions
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CCP 2019-2020 ARA 2
Resource Type Summer MW
Assumed Average EFORd/Forced Outage Rate (%) Weighted by
Summer Ratings
Assumed Average Maintenance Weeks
Weighted by Summer Ratings
Non-Intermittent Generating Resources 30,336 7.5 4.7
Intermittent Generating Resources 1,017 0.0 0.0
Import Capacity Resources 1,510 2.5 5.2
Demand Resources-On Peak 2,103 0.0 0.0
Demand Resources-Seasonal Peak 509 0.0 0.0
Demand Resources-Real Time 781 10.5 0.0
Total New England 36,255 6.6 4.0
Notes:
• Non-Intermittent Generating Resources uses the same per unit EFORd and maintenance weeks values developed for FCA #12. In the LOLE simulations, individual unit values are modeled
• Assumed summer MW weighted EFORd/FOR and maintenance weeks are shown by resource category for informational purposes
• Non-Intermittent Generating resources includes a 30 MW derating to reflect the value of the firm VJO contract
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Resource Availability Assumptions , Contd.
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CCP 2020-2021 ARA 1
Resource Type Summer MW
Assumed Average EFORd/Forced Outage Rate (%) Weighted by
Summer Ratings
Assumed Average Maintenance Weeks Weighted
by Summer Ratings
Non-Intermittent Generating Resources 30,878 7.4 4.7
Intermittent Generating Resources 912 0.0 0.0
Import Capacity Resources 1,235 3.1 6.0
Demand Resources-On Peak 2,313 0.0 0.0
Demand Resources-Seasonal Peak 596 0.0 0.0
Demand Resources-Real Time 765 10.5 0.0
Total New England 36,700 6.6 4.2
Note:
• Non-Intermittent Generating Resources uses the same per unit EFORd and Maintenance weeks values developed for FCA #12. In the LOLE simulations, individual unit values are modeled
• Assumed summer MW weighted EFORd/FOR and maintenance weeks are shown by resource category for informational purposes
• Non-Intermittent Generating resources includes a 30 MW derating to reflect the value of the firm VJO contract
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TSA Assumptions for Import Capacity Zones 2018-2019 ARA 3, 2019-2020 ARA 2 and 2020-2021 ARA 1
2018-2019 ARA 3
2019-2020 ARA 2
2020-2021 ARA 1
• DR Qualified Capacity are same values used for the ICR calculation and are shown on slide 12 • Derating Factors for DR that are used in different Capacity Zones for TSA are CT: 7%, NEMA-Boston:
14.5%, SEMA-RI: 24.5% • Peaking Generation is factored into the Non-Intermittent Generating Resources category in prior
slides
Resource Type Connecticut NEMA-Boston SEMA-RI
QC EFORD QC EFORD QC EFORD
Non-Intermittent Generating Resources 7,546 9% 2,956 9% 6,280 12%
Intermittent Generating Resources 171 0% 79 0% 112 0%
Peaking Generation 1,654 20% 305 20% 376 20%
Resource Type SENE
QC EFORD
Non-Intermittent Generating Resources 8,679 12%
Intermittent Generating Resources 190 0%
Peaking Generation 1,011 20%
Resource Type SENE
QC EFORD
Non-Intermittent Generating Resources 9,076 11%
Intermittent Generating Resources 188 0%
Peaking Generation 980 20%
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Operating Procedure No. 4 (OP 4) Assumptions - Actions 6 & 8 - 5% Voltage Reduction (MW)
• Use the 90-10 Peak load forecast net of BTM PV minus all DR
• Multiplied by the 1.5% value used by ISO Operations in estimating relief obtained from OP4 voltage reduction
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90-10 Peak Load Passive DR RTDR RTEG
Actions 6 & 8
5% Voltage
Reduction
June 2018-Sept 2018 31,183 2,415 620 0 422
October 2018-May 2019 23,878 2,368 616 0 313
June 2019-Sept 2019 31,426 2,611 781 0 421
October 2019-May 2020 24,017 2,409 779 0 312
June 2020-Sept 2020 31,683 2,909 765 0 420
October 2020-May 2021 24,135 2,849 756 0 308
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OP 4 Assumptions, Contd. - Tie Benefits (Summer MW)
• Values for 2018-2019 ARA 3 tie benefits are based on the recent study
• Values for 2019-2020 ARA 2 and 2020-2021 ARA 1 are those calculated for the corresponding FCAs (FCA #10 and FCA #11, respectively)
• Modeled in the ICR calculations with the tie line availability assumptions shown below:
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External Tie Forced Outage Rate (%) Maintenance
(Weeks)
Cross Sound Cable 0.89 1.50
Highgate 0.07 1.28
HQ Phase II 0.39 2.74
New Brunswick Ties 0.08 0.37
New York AC Ties 0 0
Control Area 2018-2019
ARA 3 2019-2020
ARA 2 2020-2021
ARA 1
Quebec over the Phase-II Interconnection 1,030 975 959
Quebec over the Highgate Interconnection 107 142 145
Maritimes over the New Brunswick Ties 425 519 500
New York over AC Ties 346 354 346
Total 1,908 1,990 1,950
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OP 4 Assumptions - Minimum Operating Reserve Requirement (MW)
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• Minimum Operating Reserve is the 10-Minute minimum Operating Reserve requirement for ISO Operations
• Modeled at 200 MW in the ICR calculation
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Summary of all MW Modeled in the ICR Values Calculations (MW)
Notes:
• Generating Capacity Resources includes a 30 MW de-rate to reflect the value of the firm VJO contract
• Intermittent Power Resources have both the summer and winter capacity values modeled
• Import Capacity Resources reflect a derating to account for TTC and each CCP’s tie benefits
• OP 4 voltage reduction includes both Action 6 and Action 8 MW assumptions
• Minimum Operating Reserve is the 10-Minute minimum Operating Reserve requirement for ISO Operations
• Tie benefits for 2019-2020 and 2020-2021 are those calculated for the corresponding FCA
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Total Capacity Breakdown 2018-19 ARA3 2019-20 ARA2 2020-21 ARA1
Generating Capacity Resources 31,147 31,352 31,790
Demand Resources 3,036 3,393 3,674
Import Resources 1,730 1,510 1,235
Tie Benefits 1,908 1,990 1,950
OP4 - Action 6 & 8 (Voltage Reduction) 422 421 420
Minimum Reserve Requirement (200) (200) (200)
Total Capacity 38,043 38,466 38,870
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