R C M E E T I N G | A G E N D A I T E M

A U G U S T 1 3 , 2 0 1 2 | R O C K P O R T M E

Includes Appendix of Assumptions

Installed Capacity Requirement (ICR) & Related Values for the 2016/17 Forward Capacity Auction (FCA7)

Objective of this Presentation• Review the proposed values, committee review and FERC filing

schedules for the:– Installed Capacity Requirement (ICR),– Transmission Security Analysis (TSA),– Local Resource Adequacy Requirement (LRA),– Local Sourcing Requirement (LSR), and – Maximum Capacity Limit (MCL)

• The ICR, LSR and MCL are collectively called the ICR Values

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ICR Review and FERC Filing Schedule

3

• ICR Values for the 2016/17 Forward Capacity Auction (FCA7)

– PSPC reviewed all assumptions – Jun 14 & Jul 31, 2012

– PSPC reviewed ISO recommendation of ICR Values – Jul 31, 2012

– RC review/vote of ISO recommendation of ICR Values – Aug 13, 2012

– PC review/vote of ISO recommendation of ICR Values – Sep 14, 2012

– File with the FERC – by Nov 2, 2012

– FCA7 conducted – Feb 4, 2013

Proposed ICR Values for the 2016/17 FCA

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ISO Proposed ICR Values for the 2016/17 FCA (MW)

5

* Total Resources consists of capacity resources used in the ICR Values calculation and excludes HQICCs for New England

2016/17 FCANew

England ConnecticutNEMA/ Boston Maine

Peak Load (50/50) 29,400 7,555 6,047 2,108

Total Resources* 35,178 9,004 3,228 3,762

Installed Capacity Requirement 34,023

NET ICR (ICR Minus 1,055 MW HQICCs) 32,968

Local Sourcing Requirement 7,603 3,209

Maximum Capacity Limit 3,709

Comparison of ICR Values (MW)- 2016/17 Vs 2015/16 FCA

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* Total Resources consists of capacity resources used in the ICR Values calculation and excludes HQICCs for New England

2016/17 FCA

2015/16 FCA

2016/17 FCA

2015/16 FCA

2016/17 FCA

2015/16 FCA

2016/17 FCA

2015/16 FCA

Peak Load (50/50) 29,400 29,380 7,555 7,610 6,047 6,070 2,108 2,135

Total Resources* 35,178 36,116 9,004 9,435 3,228 3,339 3,762 3,745

Installed Capacity Requirement 34,023 34,498

NET ICR (ICR Minus HQICCs) 32,968 33,456

Local Resource Adequacy Requirement 7,603 7,542 2,481 2,600

Transmission Security Requirement 7,489 7,536 3,209 3,289

Local Sourcing Requirement 7,603 7,542 3,209 3,289

Maximum Capacity Limit 3,709 3,888

New England Connecticut NEMA/Boston Maine

ICR Calculation Details

7

HQICCs

APkALCC

liefReLoad4OPBenefitsTieCapacityICRtRequiremenCapacityInstalled

1

)(

• 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 0.1 Reliability Criterion.

Total Capacity Breakdow n 2016/17 FCAGenerating Resources 31,591 Tie Benefits 1,870 Imports/Sales 12 Demand Resources 3,575 OP 4 Voltage Reduction - Min Res 222 Expansion Unit Capacity - Total Capacity 37,270

Installed Capacity Requirement Calculation Details 2016/17 FCAAnnual Peak 29,400 Total Capacity 37,270 Tie Benefits 1,870 HQICCs 1,055 OP4 - Action 6 & 8 (Voltage Reduction) 422 Minimum Reserve Requirement (200) ALCC 1,971 Installed Capacity Requirement 34,023 Net ICR 32,968

Reserve Margin with HQICCs 15.7%Reserve Margin without HQICCs 12.1%

Effect of Updated Assumptions on ICR

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Total

MWWeighted Forced

Outage MWWeighted Forced

OutageGeneration & IPR 31,591 4.6% 32,155 4.7% -31

Demand Resources 3,545 8.3% 3,745 14.0% -202

Imports & Sales 12 0.02% 215 0.05% 11

Load Forecast -55MW % MW %

OP 4 5% VR 422 1.50% 422 1.50% -

ICR -475

AssumptionEffect on ICR (MW)2016/2017 FCA 2015/2016 FCA

Tie Benefits & Updated External Interface Outage

Assumptions

314 MW New York 300 MW New York

-162392 MW Maritimes 328 MW Maritimes

1055 MW Quebec (HQICCs) 1042 MW Quebec (HQICCs)109 MW Quebec via Highgate 6 MW Quebec via Highgate

1,870 MW 1,676 MW

MW MW29,400 29,380

34,023 34,498

MW MW

• Methodology: Begin with model for the 2015/2016 FCA ICR calculation. Change one assumption at a time and note the change in ICR caused by each change in assumption.

CT & NEMA/Boston TSA Requirement (MW)

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FCA 7 TSA Requirement* Connecticut NEMA/Boston

Sub-area 2016 90/10 Load 8,201 6,520

Reserves (Largest unit) 1,225 1,393

Sub-area Transmission Security Need 9,426 7,913

Sub-area Existing Resources 9,004 3,228

Assumed Unavailable Capacity -797 -147

Sub-area N-1 Import Limit 2,600 4,850

Sub-area Available Resources 10,807 7,931

Sub-area Transmission Security Margin 1,381 18

TSA Requirement* =(9426-2600)/(1-797/9004) =(7913-4850)/(1-147/3228)

=7,489 =3,209

FCA 6 TSA Requirement (MW)

FCA 7 TSA Requirement (MW)

Connecticut NEMA/Boston Connecticut NEMA/BostonSub-area 2015 & 2016 90/10 Load (for FCA 6 & FCA 7 respectively) 8,250 6,530 8,201 6,520Reserves (Largest unit or loss of import capability) 1,225 1,373 1,225 1,393

Sub-area Transmission Security Need 9,475 7,903 9,426 7,913Existing Resources 9,435 3,339 9,004 3,228Assumed Unavailable Capacity -827 -239 -797 -147Sub-area N-1 Import Limit 2,600 4,850 2,600 4,850

Sub-area Available Resources 11,208 7,949 10,807 7,931

Sub-area Transmission Security Margin 1,733 47 1,381 18

TSA Requirement 7,536 3,289 7,489 3,209

2015/16 – 2016/17 TSA Requirement Comparison (MW)

• 2015/16 FCA TSA Requirement values were initially calculated and presented during the November 15, 2011 Reliability Committee Meeting.

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LRA- Connecticut

11

• All values in the table are in MW except the FORz• Resources for Rest of New England excludes HQICCs

Connecticut Zone 2016/17 FCA 2015/16 FCA Resourcez [1] 9,004 9,435 Proxy Unitsz [2] 0 0 Proxy Units Adjustmentz [3] 0 0 Firm Load Adjustmentz [4] 1,298 1,755 FORz [5] 0.0732 0.0730 LRAz [6]=[1]+[2]-([3]/(1-[5]))-([4]/(1-[5])) 7,603 7,542Rest of New England Zone Resource [7] 26,174 26,680 Proxy Units [8] 0 0 Proxy Units Adjustment [9] 0 0 Firm Load Adjustment [10] = -[4] -1,298 -1,755Total System Resource [11]=[1]+[2]-[3]-[4]+[7]+[8]-[9]-[10] 35,178 36,116

Local Resource Adequacy Requirement - Connecticut

LRA – NEMA/Boston

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• All values in the table are in MW except the FORz• Resources for Rest of New England excludes HQICCs

NEMA/BOSTON Zone 2016/17 FCA 2015/16 FCA Resourcez [1] 3,228 3,339 Proxy Unitsz [2] 0 0 Proxy Units Adjustmentz [3] 0 0 Firm Load Adjustmentz [4] 717 690 FORz [5] 0.0396 0.0667 LRAz [6]=[1]+[2]-([3]/(1-[5]))-([4]/(1-[5])) 2,481 2,600Rest of New England Zone Resource [7] 31,950 32,777 Proxy Units [8] 0 0 Proxy Units Adjustment [9] 0 0 Firm Load Adjustment [10] = -[4] -717 -690Total System Resource [11]=[1]+[2]-[3]-[4]+[7]+[8]-[9]-[10] 35,178 36,116

Local Resource Adequacy Requirement - NEMA/BOSTON

MCL - Maine

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• All values in the table are in MW except the FORz• Resources for Rest of New England excludes HQICCs

Rest of New England Zone 2016/17 FCA 2015/16 FCA Resourcez [1] 31,416 32,371 Proxy Unitsz [2] 0 0 Surplus Capacity Adjustmentz [3] 2,170 2,605 Firm Load Adjustmentz [4] -125 35 FORz [5] 0.0520 0.0580 LRAz [6]=[1]+[2]-([3]/(1-[5]))-([4]/(1-[5])) 29,259 29,568

Maine Zone Resource [7] 3,762 3,745 Proxy Units [8] 0 0 Proxy Units Adjustment [9] 0 0 Firm Load Adjustment [10] = -[4] 125 -35Total System Resource [11]=[1]+[2]-[3]-[4]+[7]+[8]-[9]-[10] 35,178 36,116

Commitment Period 2016/17 FCA 2015/16 FCAICR for New England [1] 32,968 33,456LRARestofNewEngland [2] 29,259 29,568Maximum Capacity LimitY [3]=[1]-[2] 3,709 3,888

Local RA Requirement - RestofNewEngland (for Maine MCL calculation)

Maximum Capacity Limit - Maine

Assumptions for the 2016/17 FCA 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 Local Sourcing Requirements and Maximum Capacity Limits.

– For FCA7, the following requirements are needed for the auction:• MCL for the Maine export-constrained Load Zone• LSR for the NEMA/Boston and Connecticut import-constrained Load Zones

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Assumptions for the ICR Calculations

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• Load Forecast– Load Forecast distribution

• Resource Data Based on Existing Qualified Capacity Resources for FCA7– Generating Capacity Resources– Intermittent Power Capacity Resources – 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

Load Forecast Data• Load forecast assumption from the 2012 CELT Report & 2012

Regional System Plan (RSP12) 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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Load Forecast Data – New England System Load Forecast

Probability Distribution of Annual Peak Load (MW)

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Monthly Peak Load (MW) – 50/50 Forecast

There is a distribution associated with each monthly peak. The distribution associated with the Summer Seasonal Peak (July & August) is show below:

Year 10/90 20/80 30/70 40/60 50/50 60/40 70/30 80/20 90/10 95/52016/17 27,995 28,245 28,585 28,970 29,400 29,850 30,315 30,985 31,725 32,390

Year Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May2016/17 26,415 29,400 29,400 24,400 18,890 20,450 22,960 22,960 22,065 20,720 19,575 21,265

Load Forecast Data – Comparison of RSP11 and RSP12 New England System Load Forecast Distribution Moments

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• The load forecast uncertainty is determined by the three moments of the distribution: the mean, standard deviation and skewness.

0

5000

10000

15000

20000

25000

30000

1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52

Mea

n in

MW

Week

RSP11 Vs. RSP12 2016/17 Weekly Forecast Mean

RSP11

RSP12

0500

100015002000250030003500

1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52

Stan

dard

Dev

iatio

n

Week

RSP11 Vs. RSP12 2016/17 Weekly Forecast Standard Deviation

RSP11

RSP12

0

5E+09

1E+10

1.5E+10

2E+10

2.5E+10

1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52

Skew

ness

Week

RSP11 Vs. RSP12 2016/17 Weekly Forecast Skewness

RSP11

RSP12

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Resource Data – Generating Capacity Resources (MW)

• Existing Qualified generating capacity resources for FCA7 (Updated as of July 1, 2012 to account for terminations and Significant Increases and Decreases)

• Intermittent resources have both summer and winter values modeled; non-Intermittent winter values provided for informational purpose

Summer Winter Summer WinterMAINE 3,021.666 3,249.407 241.372 359.448 NEW HAMPSHIRE 4,107.648 4,295.842 162.990 216.636 VERMONT 797.121 913.340 88.337 143.205 CONNECTICUT 7,842.842 8,368.609 191.016 204.408 RHODE ISLAND 2,637.969 2,933.862 6.399 8.834 SOUTH EAST MASSACHUSETTS 5,909.071 6,378.398 77.385 81.277 WEST CENTRAL MASSACHUSETTS 3,768.238 4,064.666 45.022 66.128 NORTH EAST MASSACHUSETTS & BOSTON 2,523.919 2,991.225 69.535 71.143

Total New England 30,608.474 33,195.349 882.056 1,151.079

Load Zone Generation Intermittent

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Resource Data – Demand Resources (MW)

• Existing Qualified Demand Resource capacity for FCA7 (Updated as of July 1, 2012 to account for terminations and Significant Increases and Decreases)

• Includes the Transmission and Distribution (T&D) Loss Adjustment (Gross-up) of 8%.

Load Zone Summer Winter Summer Winter Summer Winter Summer Winter Summer WinterMAINE 154.246 148.466 318.067 335.962 27.344 24.841 499.657 509.269NEW HAMP SHIRE 78.066 64.515 65.586 64.866 35.674 33.944 179.326 163.325VERMONT 117.810 118.251 68.118 76.051 13.371 13.371 199.299 207.673CONNECTICUT 92.396 72.453 294.961 191.687 351.794 321.951 230.543 230.028 969.694 816.119RHODE ISLAND 135.372 133.306 79.645 75.239 59.975 54.534 274.992 263.079SOUTH EAST MASSACHUSETTS 179.505 165.828 152.813 145.408 35.306 35.306 367.624 346.542WEST CENTRAL MASSACHUSETTS 175.423 164.569 44.173 40.074 175.490 160.988 55.329 54.608 450.415 420.239NORTH EAST MASSACHUSETTS & BOSTON 324.233 309.865 233.095 218.833 76.810 76.583 634.138 605.281

Total New England 1257.051 1177.253 339.134 231.761 1444.608 1399.298 534.352 523.215 3575.145 3331.527

On-Peak Seasonal Peak RT Demand Response RT Emergency Gen Total

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Resource Data – Import Capacity Resources (MW)

• Existing Qualified Import capacity resources for FCA7• System-backed imports modeled as 100% available• Total import forced outage rate weighted by Summer MW is 0.02% and Maintenance is 0.4 weeks

Import Resource

Qualified Summer

MW External Interface

NYPA - CMR 67.000 New York AC TiesNYPA - VT 14.000 New York AC TiesVJO - Highgate 31.000 Hydro-Quebec Highgate

Total MW 112.000

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Resource Data – Export Delist (MW)

• Based on Administrative Delist Bid• Already accounted for as removed capacity from the resource supplying the export in the Generating

Resources

Export Summer MWLIPA via CSC 100.000

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 (Feb 2007 – Jan 2012) 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 2007 – Dec 2011) 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

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Availability Assumptions - Generating Resources

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• 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 11,489 3.6 4.1Fossil 8,420 7.2 5.5Nuclear 4,628 2.4 3.4Hydro(Includes Pumped Storage) 2,969 3.3 5.6Combustion Turbine 2,833 7.5 2.5Diesel 214 6.5 1.1Miscellaneous 56 10.3 6.7Total System 30,608 4.8 4.4

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.

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Demand Resource Availability

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• Uses average of historical DR performance from summer 2010 and 2011

• Modeled by zone and type of DR with outage factor calculated as 1- performance/100

Load Zone SummerPerform-

ance SummerPerform-

ance SummerPerform-

ance SummerPerform-

ance SummerPerform-

anceMAINE 154.246 100% - - 318.067 100% 27.344 94% 499.657 100%NEW HAMP SHIRE 78.066 100% - - 65.586 93% 35.674 100% 179.326 97%VERMONT 117.810 100% - - 68.118 100% 13.371 80% 199.299 99%CONNECTICUT 92.396 100% 294.961 100% 351.794 72% 230.543 80% 969.694 85%RHODE ISLAND 135.372 100% - - 79.645 90% 59.975 75% 274.992 92%SOUTH EAST MASSACHUSETTS 179.505 100% - - 152.813 78% 35.306 80% 367.624 89%WEST CENTRAL MASSACHUSETTS 175.423 100% 44.173 100% 175.490 97% 55.329 77% 450.415 96%NORTH EAST MASSACHUSETTS & BOSTON 324.233 100% - - 233.095 80% 76.810 81% 634.138 90%

Total New England 1,257.051 100% 339.134 100% 1,444.608 86% 534.352 81% 3,575.145 92%

On-Peak Seasonal Peak RT Demand Response RT Emergency Gen Total

Demand Resource MW & Availability – Comparison of FCA7 and FCA6 Assumptions

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• Passive Resources are modeled as 100% available for both FCA7 and FCA6 ICR calculations

• FCA7 is calculated with historical DR performance from summer 2010 and 2011 while FCA6 DR Performance Assumptions used summer 2010 DR performance

Load Zone FCA7 FCA6 FCA7 FCA6 FCA7 FCA6

MAINE 154.246 140.449 - - 154.246 140.449 NEW HAMP SHIRE 78.066 76.787 - - 78.066 76.787 VERMONT 117.810 105.500 - - 117.810 105.500 CONNECTICUT 92.396 108.686 294.961 280.803 387.357 389.489 RHODE ISLAND 135.372 90.714 - - 135.372 90.714 SOUTH EAST MASSACHUSETTS 179.505 160.086 - - 179.505 160.086 WEST CENTRAL MASSACHUSETTS 175.423 149.178 44.173 33.037 219.596 182.215 NORTH EAST MASSACHUSETTS & BOSTON 324.233 292.618 - - 324.233 292.618

Total New England 1257.051 1124.018 339.134 313.840 1596.185 1437.858

On-Peak Seasonal Peak Total Passive

Load ZoneMAINE 318.067 100% 314.582 100% 27.344 94% 37.100 88% 345.411 100% 351.682 99%NEW HAMPSHIRE 65.586 93% 63.059 100% 35.674 100% 41.310 100% 101.260 96% 104.369 100%VERMONT 68.118 100% 59.306 100% 13.371 80% 18.493 77% 81.489 97% 77.799 95%CONNECTICUT 351.794 72% 362.340 75% 230.543 80% 275.358 67% 582.337 75% 637.698 72%RHODE ISLAND 79.645 90% 85.838 100% 59.975 75% 96.697 56% 139.620 83% 182.535 77%SOUTH EAST MASSACHUSETTS 152.813 78% 167.811 64% 35.306 80% 77.015 59% 188.119 78% 244.826 62%WEST CENTRAL MASSACHUSETTS 175.490 97% 176.049 100% 55.329 77% 98.643 49% 230.819 92% 274.692 82%NORTH EAST MASSACHUSETTS & BOSTON 233.095 80% 286.568 68% 76.810 81% 147.278 60% 309.905 80% 433.846 65%

Total New England 1444.608 86% 1515.553 84% 534.352 81% 791.894 64% 1978.960 85% 2307.447 77%

FCA6RT Demand Response RT Emergency Gen Total Active

FCA7 FCA6FCA7 FCA6 FCA7

LRA & TSA Transfer Limit Assumptions

• Transfer Limits – 2012 Regional System Plan (RSP) for 2016/17– Internal Transmission Transfer Capability

• Connecticut sub-area– N-1 Limit: 2,600 MW– N-1-1 Limit: 1,400 MW

• Boston sub-area– N-1 Limit: 4,850 MW– N-1-1 Limit: 4,175 MW

• Maine sub-area– N-1 Limit: 1,600 MW

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• Boston Import includes the impact of the Salem Harbor station retirement and of the recently certified Advanced North Shore Upgrades

• The New England East-West Solution (NEEWS) includes the Greater Springfield Reliability Program for 2014 and the Interstate Reliability Program for December 2015 however, this project has not yet been certified to be in service by 2016

• The Maine Power Reliability Program (MPRP) is expected in service by 2015 summer. This project may result in increased transfer capability across interfaces in Maine however, sufficient testing has not been completed

Resource Data Used in the LRA Calculation (MW)

30

• Resources for New England excludes HQICCs• Load and Resource assumptions are for the corresponding RSP area used as a proxy for the load zone. DR

values are the load zone values.

Type of Resource New England Connecticut NEMA/Boston MaineGenerating Resources 30,608.474 7,842.842 2,523.919 3,021.666

Intermittent Power Resources 882.056 191.016 69.535 240.555

Passive Demand Resources 1,596.185 387.357 324.233 154.246

Active Demand Resources 1,978.960 582.337 309.905 345.411 Import Resources 112.000 - - -

Total MW Modeled in LRA and MCL 35,177.675 9,003.552 3,227.592 3,761.878

Load Forecast 50/50 29,400 7,555 6,047 2,108

TSA Load & Resource Assumptions

• Load Forecast Data– 2012 CELT forecast

• Connecticut sub-area 90/10 peak load*: 8,201 MW• Boston sub-area 90/10 peak load*: 6,520 MW

• Resource Data– Based on FCA #7 Qualified Existing Capacity data

• Resources terminated effective 7/1/2012 have been removed– Generating Capacity

• Connecticut sub-area existing qualified capacity: 9,004 MW– Includes 6,310 MW of regular generation resources, 191 MW of intermittent

generation resources and 1,533 MW of peaking generation resources• Boston sub-area existing qualified capacity: 3,228 MW

– Includes 2,273 MW of regular generation resources, 70 MW of intermittent generation resources and 251 MW of peaking generation resources

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*The 90/10 peak load for the sub-area differs slightly from the 90/10 peak load for the Load Zone.

TSA Resource Unavailability Assumptions

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

• Connecticut sub-area: (Line-Gen) = 7% (Line-Line) = 6%• Boston sub-area: (Line-Gen) = 4% (Line-Line) = 2%

– Intermittent Generation Resources: 0%– Peaking Generation Resources - Operational de-rating factor

• Connecticut and Boston sub-areas: 20%– Passive Demand Resources: 0%– Non-RTEG Active Demand Resources - De-rating based on performance

factors• Connecticut sub-area: 28%• Boston sub-area: 20%

– Real-Time Emergency Generation - De-rating based on performance factors• Connecticut sub-area: 20%• Boston sub-area: 19%

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

• Use the 90-10 Peak Load Forecast minus all Passive DR & Active DR with RTEG limited to 600 MW, if necessary

• 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

Action 6 & 8 5% Voltage Reduction

Jun 2016 - Sep 2016 31,725 1,596 1,445 534 422

Oct 2016 - May 2017 23,630 1,409 1,399 523 304

OP 4 Assumptions - Tie Benefits (MW)

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

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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

Control Area MWNew Brunswick 392Quebec via Phase II 1,055Quebec via Highgate 109New York 314Total Tie Benefits 1,870

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Comparison of Tie Benefits for FCA6 and FCA7

Area2015/16 (FCA6)

(MW)2016/17 (FCA7)

(MW)Total Tie Benefits 1,676 1,870New Brunswick 328 392HQ Phase II 1,042 1,055Highgate 6 109New York AC 300 314CSC 0 0

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

Notes:

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

• 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

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Type of Resource/OP 4 2016/17 FCA

Generating Resources 30,708.474

Intermittent Power Resources 882.056

Demand Resources 3,575.145

Import Resources 112.000

Export Delist (100.000)

OP 4 Voltage Reduction 422.000

Minimum Operating Reserve (200.000)

Tie Benefits (Includes 1,055 MW HQICCs) 1,870.000

Total MW Modeled in ICR 37,269.675

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