ISO-NE PUBLIC

P S P C M E E T I N G N O . 3 2 7 | A G E N D A I T E M 2 . 0

A U G U S T 1 7 , 2 0 1 7 | H O L Y O K E M A

Manasa Kotha

Proposed Installed Capacity Requirement (ICR) Values for the 2021-2022 Forward Capacity Auction (FCA #12)

ISO-NE PUBLIC

Objective of this Presentation • Review the ICR Values* development and FERC filing schedules • Provide final review of assumptions that were presented at the June 22,

2017 PSPC Meeting • Review the proposed ICR Values* including:

– Installed Capacity Requirement (ICR) – For the import-constrained Southeast New England (SENE) Capacity Zone

(combined Load Zones of NEMA/Boston, SEMA and RI) • Transmission Security Analysis (TSA) • Local Resource Adequacy Requirement (LRA) • Local Sourcing Requirement (LSR)

– MCL for the export-constrained Northern New England (NNE) Capacity Zone (combined Load Zones of Maine, VT and NH)

– Marginal Reliability Impact Demand Curves (MRI Demand Curves)

2

* The ICR, LSR, MCL and the Demand Curves are collectively called the ICR Values

ISO-NE PUBLIC

Proposed ICR Review and FERC Filing Schedule

• ICR for the 2021-2022 Capacity Commitment Period (CCP) (FCA #12) – PSPC review Capacity Zone determinations – May 18, 2017

– PSPC final review of all assumptions – Jun 22, 2017

– PSPC review of ISO recommendation of ICR Values – Aug 17, 2017

– RC review/vote of ISO recommendation of ICR Values – Sep 19, 2017

– PC review/vote of ISO recommendation of ICR Values – Oct 13, 2017

– File with the FERC – by Nov 7, 2017

– FCA #12 begins – Feb 5, 2018

3

ISO-NE PUBLIC

ISO-NE INTERNAL USE ISO-NE PUBLIC

PROPOSED ICR VALUES FOR CCP 2021-2022 (FCA #12)

4

ISO-NE PUBLIC

ISO Proposed ICR Values for the CCP 2021-2022 FCA #12 (MW)

5

• Existing Capacity Resources are the Existing Qualified capacity resources for FCA #12 at the time of the ICR calculation and reflects retirements and terminations

• 50/50 peak load shown for informational purposes

CCP 2021-2022 (FCA #12) New

England

Southeast New

England

Northern New

England Peak Load (50/50) Net of BTM PV 29,436 12,327 5,711

Existing Capacity Resources 34,567 11,715 8,294

Installed Capacity Requirement 34,683

NET ICR (ICR Minus 958 MW HQICCs) 33,725

Local Sourcing Requirement 10,018

Maximum Capacity Limit 8,790

ISO-NE PUBLIC

Comparison of ICR Values (MW) CCP 2021-2022 (FCA #12) Vs CCP 2020-2021 (FCA #11)

6

Notes:

• Existing Capacity Resources are the Existing Qualified capacity resources for each FCA at the time of the calculation and reflect retirements and terminations

• For details on the FCA #11 (2019-2020) ICR Values calculation see: https://www.iso-ne.com/static-assets/documents/2016/09/a2_2020_21_fca11_icr_values_results.pdf

• 50/50 peak load shown for informational purposes

New England Southeast New

England Northern New

England

2021-2022 FCA #12

2020-2021 FCA #11

2021-2022 FCA #12

2020-2021 FCA #11

2021-2022 FCA #12

2020-2021 FCA #11

Peak Load Net of BTM PV (50/50) 29,436 29,601 12,327 12,153 5,711 5,882

Existing Capacity Resources 34,567 34,389 11,715 11,403 8,294 8,243

Installed Capacity Requirement 34,683 35,034

NET ICR (ICR Minus HQICCs) 33,725 34,075

Local Resource Adequacy Requirement 9,705 9,580

Transmission Security Analysis Requirement 10,018 9,810

Local Sourcing Requirement 10,018 9,810

Maximum Capacity Limit 8,790 8,980

ISO-NE PUBLIC

ICR Calculation Details

7

HQICCs

APkALCC

liefReLoad4OPBenefitsTieCapacityICRtRequiremenCapacityInstalled ++

−−=

1)(

Notes: • All values in the table are in MW except the Reserve Margin shown in percent • ALCC is the “Additional Load Carrying Capability” used to bring the system to the target Reliability Criterion

Total Capacity Breakdown CCP 2021-2022 FCA #12 ICR

Generating Resources 31,273 Demand Resources 3,212 Import Resources 82 Tie Benefits 2,020 OP4 - Action 6 & 8 (Voltage Reduction) 431 Minimum Reserve Requirement (200) Proxy Unit Capacity - Total Capacity 36,818

Installed Capacity Requirement Calculation Details

CCP 2021-2022 FCA #12 ICR

Annual Peak 29,435 Total Capacity 36,818 Tie Benefits 2,020 HQICCs 958 OP4 - Action 6 & 8 (Voltage Reduction) 431 Minimum Operating Reserve Requirement (200) ALCC 735 Installed Capacity Requirement 34,683 Net ICR 33,725

Reserve Margin with HQICCs 17.8% Reserve Margin without HQICCs 14.6%

ISO-NE PUBLIC 8

Cost of New Entry (CONE) for the Demand Curve

• CONE for the Cap of the Demand Curve for FCA #12 has been calculated as: – Gross CONE = $11.35/kW-month

– Net CONE = $8.04/kW-month

• See link for Forward Capacity Market (FCM) parameters by CCP:

http://www.iso-ne.com/markets-operations/markets/forward-capacity-market

ISO-NE PUBLIC

Effect of Updated Assumptions on ICR

9

Notes: • Methodology: Using the model associated with the 2020-2021 FCA #11 ICR calculation, change one

assumption at a time and note the change in ICR • Generation forced outage assumption is a weighted average of individual generator's 5-year average EFORd

and Intermittent resources rated as 100% available • * See next slide for load forecast assumption change details

Total

MWWeighted Forced

Outage (%) MWWeighted Forced

OutageGeneration & IPR 31,273 7.1% 31,375 6.9% 106

Demand Resources 3,212 1.5% 2,926 1.8% -8Imports 89 0.0% 89 0.0% -

Load Forecast & BTM PV *MW % MW %

OP 4 5% VR 431 1.50% 437 1.50% 6

ICR -351

AssumptionEffect on ICR (MW)2021-2022 FCA#12 2020-2021 FCA#11

Tie Benefits

413 MW New York 346 MW New York

-69506 MW Maritimes 500 MW Maritimes

958 MW Quebec (HQICCs) 959 MW Quebec (HQICCs)143 MW Quebec via Highgate 145 MW Quebec via Highgate

2,020 MW 1,950 MW

34,683 35,034

MW MW29,435 29,601

MW MW

ISO-NE PUBLIC 10

Effect of Updated Assumptions on ICR -Load Forecast

• -395 MW: total change in load forecast & BTM PV assumptions +135 MW: increase in ICR due to the gross 2017 CELT load forecast and

load forecast uncertainty for 2021 versus 2016 CELT load forecast and load forecast uncertainty for 2020

-490 MW: decrease in ICR due to the 2017 BTM PV forecast modeled in an hourly profile versus the 2016 BTM PV modeled with the Reliability Hour methodology -155 MW: portion of the decrease due to the increased penetration of BTM

PV (2017 BTM PV forecast versus 2016 BTM PV forecast modeled with the Reliability Hour methodology)

-335 MW: portion of the decrease due to the change in methodology for modeling BTM PV (2017 BTM PV forecast modeled in an hourly profile versus Reliability Hour methodology)

ISO-NE PUBLIC

LRA – SENE

11

Notes: • All values in the table are in MW except the Forced Outage Ratez (FORz)

Local Resource Adequacy Requirement - SENE

Southeast New England Capacity Zone 2021-2022 FCA #12 2020-2021 FCA #11

Resourcez [1] 11,715 11,403

Proxy Unitsz [2] 0 0

Firm Load Adjustmentz [3] 1,848 1,669

FORz [4] 0.081 0.085

LRAz [5]=[1]+[2]-([3]/(1-[4])) 9,705 9,580

Rest of New England Zone

Resource [6] 22,852 22,986

Proxy Units [7] 0 0

Firm Load Adjustment [8] = -[3] -1,848 -1,669

Total System Resources [9]=[1]+[2]-[3]+[6]+[7]-[8] 34,567 34,389

ISO-NE PUBLIC

TSA Requirement – SENE (MW)

12

SENE Zone 2021-2022 FCA #12

2020-2021 FCA #11

Sub-area 90/10 Load* 13,413 13,190

Reserves (Largest unit or loss of import capability) 1,413 1,413

Sub-area Transmission Security Need 14,826 14,603

Existing Resources 11,715 11,403

Assumed Unavailable Capacity -1,043 -1,054

Sub-area N-1 Import Limit 5,700 5,700

Sub-area Available Resources 16,372 16,049

TSA Requirement 10,018 9,810

Notes: • *Load forecast is net of BTM PV • All values have been rounded off to the nearest whole number • Information on the 2020-2021 CCP (FCA #11) TSA calculation available at: https://www.iso-

ne.com/static-assets/documents/2016/09/a2_2020_21_fca11_icr_values_results.pdf

ISO-NE PUBLIC

MCL - NNE

13

Notes: • All values in the table are in MW except the FORz

LRA - RestofNewEngland (for NNE MCL calculation)

Rest of New England Zone 2021-2022 FCA #12 2020-2021 FCA #11 Resourcez [1] 26,273 26,147

Proxy Unitsz [2] 0 0

Surplus Capacity Adjustmentz [3] 850 305

Firm Load Adjustmentz [4] 391 671

FORz [5] 0.073 0.072

LRAz [6]=[1]+[2]-([3]/(1-[5]))-([4]/(1-[5])) 24,935 25,095

NNE Zone

Resource [7] 8,294 8,243

Proxy Units [8] 0 0

Firm Load Adjustment [9] = -[4] -391 -671

Total System Resources [10]=[1]+[2]-[4]+[7]+[8]-[9] 34,567 34,389

Maximum Capacity Limit – NNE

Commitment Period 2021-2022 FCA #12 2020-2021 FCA #11 NICR for New England [1] 33,725 34,075

LRARestofNewEngland [2] 24,935 25,095

Maximum Capacity LimitY [3]=[1]-[2] 8,790 8,980

ISO-NE PUBLIC

FCA #12 System-wide MRI Curve

14

0.0

0.4

0.8

1.2

1.6

2.0

2.4

2.8

3.2

31.7 32.2 32.7 33.2 33.7 34.2 34.7 35.2 35.7 36.2 36.7

-Mar

gina

l Rel

iabi

lity

Impa

ct (h

ours

/yea

r)

System Capacity (GW)

Net ICR

ISO-NE PUBLIC

FCA #12 Final System-wide Demand Curve

15

$0

$2

$4

$6

$8

$10

$12

$14

$16

31.7 32.2 32.7 33.2 33.7 34.2 34.7 35.2 35.7 36.2 36.7

Pric

e ($

/kW

-mon

th)

System Capacity (GW)

Net ICR

ISO-NE PUBLIC

FCA #12 SENE Demand Curve

16

P_SYS + $0

P_SYS + $2

P_SYS + $4

P_SYS + $6

P_SYS + $8

P_SYS + $10

P_SYS + $12

P_SYS + $14

P_SYS + $16

8.00 8.25 8.50 8.75 9.00 9.25 9.50 9.75 10.00 10.25 10.50 10.75 11.00 11.25 11.50

SENE Capacity (GW)

maximum total price is $12.864

LSR

ISO-NE PUBLIC

FCA #12 NNE Demand Curve

17

-$16 + P_SYS

-$14 + P_SYS

-$12 + P_SYS

-$10 + P_SYS

-$8 + P_SYS

-$6 + P_SYS

-$4 + P_SYS

-$2 + P_SYS

$0 + P_SYS8.00 8.25 8.50 8.75 9.00 9.25 9.50 9.75 10.00 10.25 10.50

NNE Capacity (GW)

MCL

minimum total price is $0.00

ISO-NE PUBLIC

ISO-NE INTERNAL USE ISO-NE PUBLIC

FCA #12 & FCA #11 DEMAND CURVE COMPARISONS

18

ISO-NE PUBLIC

System MRI Curves

19

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

2.2

2.4

31,500 32,500 33,500 34,500 35,500 36,500

- Mar

gina

l Rel

iabi

lity

Impa

ct (h

ours

/yea

r)

System Capacity (MW)

FCA #11

FCA #12

Net ICR

ISO-NE PUBLIC

System MRI Curves - Relative to Net ICR

20

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

2.2

2.4

-2,500 -1,500 -500 500 1,500 2,500

- Mar

gina

l Rel

iabi

lity

Impa

ct (h

ours

/yea

r)

System Capacity Relative to Net ICR (MW)

FCA #11

FCA #12

Net ICR

ISO-NE PUBLIC

System Demand Curves

21

$0

$2

$4

$6

$8

$10

$12

$14

$16

$18

$20

32,000 33,000 34,000 35,000 36,000 37,000

Pric

e ($

/kW

-mon

th)

System Capacity (MW)

FCA #11

FCA #12

Net ICR

ISO-NE PUBLIC

System Demand Curves - Relative to Net ICR

22

$0

$2

$4

$6

$8

$10

$12

$14

$16

$18

$20

-2,000 -1,500 -1,000 -500 0 500 1,000 1,500 2,000 2,500

Pric

e ($

/kW

-mon

th)

System Capacity Relative to Net ICR (MW)

FCA #11

FCA #12

Net ICR

ISO-NE PUBLIC

SENE MRI Curves

23

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

2.2

2.4

8,500 9,000 9,500 10,000 10,500 11,000

- Mar

gina

l Rel

iabi

lity

Impa

ct (h

ours

/yea

r)

SENE Capacity (MW)

FCA #11

FCA #12

LSR

ISO-NE PUBLIC

SENE MRI Curves - Relative to LSR

24

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

-1,500 -1,000 -500 0 500 1,000

- Mar

gina

l Rel

iabi

lity

Impa

ct (h

ours

/yea

r)

System Capacity Relative to Net ICR (MW)

FCA #11

FCA #12

LSR

ISO-NE PUBLIC

SENE Demand Curves

25

P_SYS + $0

P_SYS + $2

P_SYS + $4

P_SYS + $6

P_SYS + $8

P_SYS + $10

P_SYS + $12

P_SYS + $14

P_SYS + $16

P_SYS + $18

P_SYS + $20

8,500 9,000 9,500 10,000 10,500 11,000

Pric

e ($

/kW

-mon

th)

SENE Capacity (MW)

FCA #11

FCA #12

LSR

ISO-NE PUBLIC

SENE Demand Curves - Relative to LSR

26

P_SYS + $0

P_SYS + $2

P_SYS + $4

P_SYS + $6

P_SYS + $8

P_SYS + $10

P_SYS + $12

P_SYS + $14

P_SYS + $16

P_SYS + $18

P_SYS + $20

-1,500 -1,000 -500 0 500 1,000

Pric

e ($

/kW

-mon

th)

SENE Capacity Relative to LSR (MW)

FCA #11

FCA #12

LSR

ISO-NE PUBLIC

NNE MRI Curves

27

-1.0

-0.8

-0.6

-0.4

-0.2

0.08,000 8,500 9,000 9,500 10,000 10,500

- Mar

gina

l Rel

iabi

lity

Impa

ct (h

ours

/yea

r)

NNE Capacity (MW)

FCA #11

FCA #12

MCL

ISO-NE PUBLIC

NNE MRI Curves - Relative to MCL

28

-0.8

-0.6

-0.4

-0.2

0.0-1,000 -500 0 500 1,000 1,500

- Mar

gina

l Rel

iabi

lity

Impa

ct (h

ours

/yea

r)

NNE Capacity Relative to MCL (MW)

FCA #11

FCA #12

MCL

ISO-NE PUBLIC

NNE Demand Curves

29

-$14 + P_SYS

-$12 + P_SYS

-$10 + P_SYS

-$8 + P_SYS

-$6 + P_SYS

-$4 + P_SYS

-$2 + P_SYS

$0 + P_SYS8,000 8,500 9,000 9,500 10,000 10,500

Pric

e ($

/kW

-mon

th)

NNE Capacity (MW)

FCA #11

FCA #12

MCL

ISO-NE PUBLIC

NNE Demand Curves - Relative to MCL

30

-$14 + P_SYS

-$12 + P_SYS

-$10 + P_SYS

-$8 + P_SYS

-$6 + P_SYS

-$4 + P_SYS

-$2 + P_SYS

$0 + P_SYS-1,000 -500 0 500 1,000 1,500

Pric

e ($

/kW

-mon

th)

NNE Capacity Relative to MCL (MW)

FCA #11

FCA #12

MCL

ISO-NE PUBLIC 31

ISO-NE PUBLIC

ISO-NE INTERNAL USE ISO-NE PUBLIC

ASSUMPTIONS FOR CCP 2021-2022 (FCA #12) ICR VALUES CALCULATION

32

ISO-NE PUBLIC

Modeling the New England Control Area • The GE MARS model is used to calculate the ICR and Values

– Internal transmission constraints are not modeled in the ICR calculation. All loads and resources are assumed to be connected to a single electric bus

– Internal transmission constraints are addressed through LSR and MCL • LSR is calculated for the SENE Capacity Zone; modeled as an import-

constrained Capacity Zone in FCA #12 • MCL is calculated NNE Capacity Zone; modeled as an export-

constrained Capacity Zone in FCA #12 – The Marginal Reliability Impact (MRI) method for calculating

Demand Curves is used to determine System and Capacity Zone Demand Curves

33

ISO-NE PUBLIC 34

Assumptions for the ICR Calculations • Load Forecast

– Net of Behind the Meter (BTM) Photovoltaic (PV) forecast – Load Forecast distribution

• Resource Data Based on Existing Qualified Capacity Resources for FCA #12 – 521 MW of retirement and permanent de-list bids have been deducted from the

Existing resources’ Qualified Capacity – Generating Capacity Resources – Intermittent Power Capacity 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 • Maritimes • New York

– 5% Voltage Reduction

ISO-NE PUBLIC

Load Forecast Data

• Load forecast assumption from the 2017 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

35

ISO-NE PUBLIC

Modeling of BTM PV in ICR (MW)

• FCA #12 ICR 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 32.7%* of PV nameplate forecast from the Distributed Generation Forecast Working Group (DGFWG) for 2021-2022 (same methodology as the 2016 PV forecast)

• In the TSA, the published 90/10 Net Load Forecast for the SENE sub-areas is used

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

36

ISO-NE PUBLIC

Load Forecast Data – New England System Load Forecast

Probability Distribution of Seasonal Peak Load (MW)

37

Monthly Peak Load (MW) – 50/50 Forecast

• Corresponds to the reference forecast labeled “1.2 REFERENCE - With reduction for BTM PV“ from section 1.1 of the 2017 CELT Report

• From Table 1.6 - Seasonal Peak Load Forecast Distributions (Forecast is Reference with reduction for BTM PV) from the 2017 CELT

Year Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May2021-2022 25,474 29,436 29,436 23,779 18,865 20,501 23,556 23,556 22,761 21,916 18,367 20,197

10/90 20/80 30/70 40/60 50/50 60/40 70/30 80/20 90/10 95/5 Summer 2021 27,925 28,203 28,562 28,984 29,436 29,930 30,432 31,140 31,964 32,693

Winter 2021-2022 23,116 23,240 23,337 23,402 23,556 23,713 23,888 23,994 24,255 24,635

Notes: • The Reference load forecast shown is for informational purposes; in the probabilistic ICR calculations, the

GE MARS model sees an hourly distribution of loads with the BTM PV modeled in an hourly profile

ISO-NE PUBLIC

Comparison of Sub-area 50/50 Gross Peak Load Forecasts (MW) 2017 CELT vs. 2016 CELT

Notes: • Comparisons of the 2017 versus the 2016 CELT load forecasts show that while the overall New England load

forecast went down, the forecast for the SENE sub-areas has increased • Sum of the sub-areas may not equal the New England value due to rounding

2016 CELT 2017 CELTArea 2017 2017 Difference

BHE 317 305 -12ME 1,018 1,010 -8SME 808 770 -38NH 2,292 2,183 -109VT 1,372 1,390 18Boston 6,198 6,166 -32CMA/NEMA 1,835 1,834 -1WMA 2,172 2,177 5SEMA 3,039 3,171 132RI 2,687 2,691 4CT 3,745 3,669 -76SWCT 2,462 2,495 33NOR 1,364 1,285 -79New England 29,307 29,146 -161

SENE 11,924 12,027 103NNE 5,807 5,657 -150

Area DifferenceBHE 327 315 -12ME 1,052 1,044 -8SME 836 798 -38NH 2,427 2,277 -150VT 1,425 1,429 4Boston 6,485 6,450 -35CMA/NEMA 1,927 1,938 11WMA 2,271 2,284 13SEMA 3,176 3,343 167RI 2,831 2,819 -12CT 3,876 3,763 -113SWCT 2,572 2,549 -23NOR 1,374 1,314 -60New England 30,579 30,322 -257

SENE 12,492 12,612 120NNE 6,067 5,863 -204

2016 CELT 2021

2017 CELT 2021

38

ISO-NE PUBLIC

Comparison of Sub-area Load Forecast, cont.

• The increase is due to the Massachusetts economy growing faster relative to the other New England states – Gross State Product (GSP) in Massachusetts is expected to grow at a

compound annual growth rate of 2.1% through the forecast horizon, more than any other New England state

– As of 2016 Massachusetts comprised about 50 percent of economic activity (Gross State Product) in New England. That share is forecasted to increase to about 51.25% in 10 years

39

ISO-NE PUBLIC

Resource Data – Generating Capacity Resources (MW)

Notes: • Existing Qualified generating capacity resources for FCA #12 • Intermittent resources have both summer and winter values modeled; non-Intermittent winter values provided

for informational purpose • Reflects a 30 MW the Citizens Block Load de-rate from generating resources

Summer Winter Summer Winter Summer WinterMAINE 2,965.014 3,155.700 222.854 342.987 3,187.868 3,498.687 NEW HAMPSHIRE 4,113.377 4,277.971 162.450 225.353 4,275.827 4,503.324 VERMONT 217.308 257.178 67.813 116.841 285.121 374.019 CONNECTICUT 9,314.685 9,787.362 152.357 166.061 9,467.042 9,953.423 RHODE ISLAND 2,406.264 2,606.359 8.094 17.039 2,414.358 2,623.398 SOUTH EAST MASSACHUSETTS 4,456.155 4,819.233 100.293 80.574 4,556.448 4,899.807 WEST CENTRAL MASSACHUSETTS 3,745.817 4,013.923 92.412 117.198 3,838.229 4,131.121 NORTH EAST MASSACHUSETTS & BOSTON 3,171.441 3,624.485 77.043 72.905 3,248.484 3,697.390

Total New England 30,390.061 32,542.211 883.316 1,138.958 31,273.377 33,681.169

Load Zone Non-Intermittent Generation Intermittent Generation Total

40

ISO-NE PUBLIC 41

Resource Data – Import Capacity Resources (MW)

Notes: • Existing Qualified Import capacity resources for FCA #12 • A 30 MW derating is applied to Citizens Block Load (modeled as a generator) • Modeled with 100% resource availability

Import Resource

Qualified Summer

MW External InterfaceNYPA - CMR 68.800 New York AC TiesNYPA - VT 13.000 New York AC TiesTotal MW 81.800

ISO-NE PUBLIC

Resource Data – Demand Resources (MW)

Notes: • Existing Qualified Demand Resource capacity for FCA #12 • Includes the Transmission and Distribution (T&D) Loss Adjustment (Gross-up) of 8%

Load Zone Summer Winter Summer Winter Summer Winter Summer WinterMAINE 146.618 135.036 - - 138.682 156.578 285.300 291.614NEW HAMPSHIRE 119.214 96.834 - - 17.209 16.489 136.423 113.323VERMONT 89.117 79.935 - - 34.079 39.685 123.196 119.620CONNECTICUT 88.536 63.689 508.842 528.347 91.842 91.137 689.220 683.173RHODE ISLAND 250.956 246.720 - - 40.023 36.523 290.979 283.243SOUTH EAST MASSACHUSETTS 354.593 341.773 - - 45.682 43.807 400.275 385.580WEST CENTRAL MASSACHUSETTS 371.582 368.369 39.597 18.003 71.029 67.374 482.208 453.746NORTH EAST MASSACHUSETTS & BOSTON 733.071 700.255 - - 70.898 70.898 803.969 771.153

Grand Total 2,153.69 2,032.61 548.439 546.350 509.444 522.491 3,211.57 3,101.45

On-Peak Seasonal Peak Real-time Demand Response Total

42

ISO-NE PUBLIC

Sub-area Resource and 50/50 Peak Load Forecast Assumptions Used in LRA and MCL Calculations (MW)

Notes: • LRA is calculated for the SENE Capacity Zones; MCL is calculated for the NNE Capacity Zone • Zonal requirements are determined using the load forecast and resource assumptions for the appropriate

RSP sub-areas as the transmission transfer capability analysis is performed using the RSP 13-bubbles for the import and export constrained interfaces

• Generating resource assumptions for the RSP sub-areas are consistent with the Load Zone values. Reflects a 30 MW derating to Citizens Block Load

• The 50/50 load forecast values for the Capacity Zones are the sum of the appropriate RSP sub-areas and are shown for informational purposes

Resource Type SENE NNETotal New England

Generator 10,033.860 7,295.699 30,390.061 Intermittent Generator 185.430 453.117 883.316 Import - - 81.800 On-Peak DR 1,338.620 354.949 2,153.687 Seasonal-Peak DR - - 548.439 Real-Time Demand Response 156.603 189.970 509.444

Total 11,714.513 8,293.735 34,566.747

SENE NNE New England50/50 Load Forecast Net BTM PV 12,327 5,711 29,436

43

ISO-NE PUBLIC

Proxy Unit Characteristics

• Proxy unit characteristics based on a study conducted in 2014 using the 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

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 unchanged

44

ISO-NE PUBLIC

LRA, TSA & MCL Internal Transmission Transfer Capability Assumptions (MW)

• Internal Transmission Transfer Capability – Southeast New England Import

• N-1 Limit: 5,700 • N-1-1 Limit: 4,600

– Northern New England Export (North-South interface) • N-1 Limit: 2,725

45

Notes: • Transmission transfer capability limits – presented at the Planning Advisory Committee (PAC) on March 22,

2017 (CEII): https://smd.iso-ne.com/operations-services/ceii/pac/2017/03/a8_fca_12_zonal_boundary_determination.pdf

ISO-NE PUBLIC

Availability Assumptions - Generating Resources

• Forced Outages Assumption – Each generating unit’s Equivalent Forced Outage Rate on Demand (non-

weighted EFORd) modeled – Based on a 5-year average (Jan 2012 – Dec 2016) of generator

submitted Generation Availability Data System (GADS) data – NERC GADS Class average data is used for immature units

• Scheduled Outage Assumption – Each generating unit weeks of Maintenance modeled – Based on a 5-year average (Jan 2012 – Dec 2016) of each generator’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 units

46

ISO-NE PUBLIC

Resource Availability Assumptions 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 large CTs greater than 200 MW (currently only applies to Canal 3)

47

ISO-NE PUBLIC

Availability Assumptions - Generating Resources

48

Notes: • Assumed summer MW weighted EFORd and Maintenance Weeks are shown by resource category for

informational purposes. In the LOLE simulations, individual unit values are modeled

Resource Category Summer MW

Assumed Average EFORd (%) Weighted by Summer Ratings

Assumed Average Maintenance Weeks

Weighted by Summer Ratings

Combined Cycle 14,661 3.9 5.0Fossil 5,729 19.3 5.6Combustion Turbine 3,507 10.4 2.6Nuclear 3,343 1.9 3.6Hydro (Includes Pumped Storage) 2,998 3.5 4.7Diesel 129 9.3 1.6Miscellaneous 23 10.0 4.7

Total System 30,390 7.3 4.6

ISO-NE PUBLIC

Changes in Generator Availability

• ISO-NE uses a 5-year rolling calculation of GADS EFORd for each generator – This year’s ICR calculation is using the EFORd from PowerGads

software for each generator based on outages reported from the years 2012 – 2016

• The New England total of 5-year individual EFORd for each generator weighted by its qualified capacity for FCA #12 is 7.3% – The FCA #11 New England average was 7.1%

• If generator availability trends continue to improve, EFORD will slowly see a decrease as the years with lower availability drop out of the 5-year average, particularly 2012 and 2013

49

ISO-NE PUBLIC

Availability Assumptions - Intermittent Power Resources

• 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

50

ISO-NE PUBLIC

Demand Resource Availability

Notes:

• Uses historical DR performance from summer & winter 2012 – 2016. See the May 18, 2017 PSPC presentation for more information: 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

Load ZoneSummer

(MW)Perform- ance (%)

Summer (MW)

Perform- ance (%)

Summer (MW)

Perform- ance (%)

Summer (MW)

Perform- ance (%)

MAINE 146.618 100 - - 138.682 100 285.300 100NEW HAMPSHIRE 119.214 100 - - 17.209 92 136.423 99VERMONT 89.117 100 - - 34.079 97 123.196 99CONNECTICUT 88.536 100 508.842 100 91.842 92 689.220 99RHODE ISLAND 250.956 100 - - 40.023 76 290.979 97SOUTH EAST MASSACHUSETTS 354.593 100 - - 45.682 86 400.275 98WEST CENTRAL MASSACHUSETTS 371.582 100 39.597 100 71.029 82 482.208 97NORTH EAST MASSACHUSETTS & BOSTON 733.071 100 - - 70.898 85 803.969 99

Total New England 2,153.687 100 548.439 100 509.444 90 3,211.570 98

On-Peak Seasonal Peak RT Demand Response Total

51

ISO-NE PUBLIC

OP 4 Assumptions Action 6 & 8 - 5% Voltage Reduction (MW)

Notes:

• Uses the 90-10 peak load forecast minus BTM PV and all passive & active DR

• Multiplied by the 1.5% value used by ISO Operations in estimating relief obtained from OP 4 voltage reduction

52

90-10 Peak Load Passive DR RTDR

Action 6 & 8 5% Voltage Reduction

Jun 2021 - Sep 2021 31,964 2,702 509 431

Oct 2021 - May 2022 24,255 2,579 522 317

ISO-NE PUBLIC

OP 4 Assumptions Tie Benefits (MW)

53

External Tie

Forced Outage Rate

(%)Maintenance

(Weeks)HQ Phase II 0.39 2.7Highgate 0.07 1.3New Brunswick Ties 0.08 0.4New York AC Ties 0 0Cross Sound Cable 0.89 1.5

• Based on the results of the 2021-2022 Tie Benefits Study. For more information on the study see: https://www.iso-ne.com/static-assets/documents/2017/06/pspc_6_22_2017_tie_benefits_study.pdf

• Modeled in the ICR calculations with the tie line availability assumptions shown below:

2021-2022 (FCA #12) 2020-2021 (FCA #11)

New Brunswick 506 500

HQ Phase II 958 959

Highgate 143 145

New York AC 413 346

Total Tie Benefits 2,020 1,950

ISO-NE PUBLIC

OP 4 Assumptions Minimum Operating Reserve Requirement(MW)

54

• Minimum Operating Reserve is the 10-Minute minimum Operating Reserve requirement for ISO Operations

• Modeled at 200 MW in the ICR calculation

ISO-NE PUBLIC

FCA #12 TSA Requirements Assumptions

• The Southeast New England (SENE) Capacity Zone was identified as the only import-constrained Capacity Zone for FCA #12

• The TSA Requirement is calculated for this Capacity Zone

• The calculation of the TSA Requirements rely on the latest load forecast, resource data and resource availability assumptions in addition to the transmission topology that was certified for FCA #12*

• The TSA Requirement is calculated as:

*January 17, 2017 Reliability Committee Meeting Materials

55

(Need – Import Limit)

1 - ( Assumed Unavailable Capacity / Existing Resources) TSA Requirement

ISO-NE PUBLIC

FCA #12 TSA Requirements Assumptions Detailed Assumptions

• Load Forecast Data – 2017 CELT Net forecast (adjusted for BTM PV forecast)

• SENE sub-area 90/10 peak load: 13,413 MW

• Resource Data for SENE – 2021-2022 Existing Capacity Qualification data as of June 05, 2017

• Generating capacity: 10,220* MW – Includes 9,101 MW of regular generation resources and 933 MW peaking

generation resources, 186 MW of intermittent generation resources • Passive Demand Resources: 1,338MW • Active Demand Resources**: 157 MW

Notes: • * Retirement De-list bids are deducted from the Existing Capacity Qualification data • **RTEGs are no longer qualified beginning FCA #12 • All values have been rounded off to the nearest whole number

56

ISO-NE PUBLIC

FCA #12 TSA Requirements Assumptions Detailed Assumptions, cont.

• Resource Unavailability Assumptions – Regular Generation Resources - Weighted average EFORd

• SENE sub-area: 10% – Peaking Generation Resources: 20% – Passive Demand Resources: 0% – Active Demand Resources - De-rating based on performance factors

• NEMA/Boston sub-area: 14% • SEMA sub-area: 14% • RI sub-area: 24%

Note: All values have been rounded off to the nearest whole number

57

ISO-NE PUBLIC

Summary of all MW Modeled in the ICR Calculations (MW)

Notes:

• The tie benefits assumptions are the results of the 2021-2022 Tie Benefits Study

• Intermittent Power Resources have both the summer and winter capacity values modeled

• The import derating is removed from the generating resources MW

• 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

58

Type of Resource/OP 4 2021-2022 FCAGenerating Resources 30,420.061 Intermittent Power Resources 883.316 Demand Resources 3,211.570 Import Resources 81.800 Import Deratings (30.000) OP 4 Voltage Reduction 431.000 Minimum Operating Reserve (200.000) Tie Benefits (Includes 958 MW of HQICC) 2,020.000 Proxy Units -

Total MW Modeled in ICR 36,817.747

ISO-NE PUBLIC 59