draft installed capacity requirement (icr) and related values for the 2014/15 forward capacity...

DRAFT

Installed Capacity Requirement (ICR) and Related Values for the 2014/15 Forward Capacity Auction (FCA5)

Maria Agustin

DRAFT © 2011 ISO New England Inc. 2

Objective of this Presentation

• Present the ISO New England recommended Installed Capacity Requirement (ICR), Local Sourcing Requirements (LSR) and Maximum Capacity Limit (MCL) for the 2014/15 Capacity Commitment Period.

• Share the results of ICR scenarios studied.

• Review load, capacity and transmission assumptions used to simulate the New England bulk power supply system for calculating the ICR and Related Values, if necessary.


2014/15 ICR Schedule

• PSPC review of assumptions – Oct 28 - Dec 9, 2010

• PSPC review of ISO recommendation of ICR values – Jan 6 &13, 2011

• RC review/vote of ISO recommendation of ICR values – Jan 18, 2011

• PC review/vote of ISO recommendation of ICR values – Feb 4, 2011

• File with the FERC – by Mar 4, 2011

• FCA5 – Jun 6, 2011

DRAFT

ICR Scenarios of Tie Benefits

• Case 1: ISO Proposed Methodology with New Brunswick import at 700 MW and Cross-Sound Cable (CSC) at 0 MW and internal constraints modeled

• Case 2: ISO Proposed Methodology with New Brunswick import at 1,000 MW and CSC at 330 MW and internal constraints modeled

• Case 3: Existing Tie Benefits Methodology with New Brunswick import at 1,000 MW and CSC at 330 MW; no internal constraints modeled

© 2011 ISO New England Inc. 4

DRAFT

Why these Scenarios were Chosen

• Case 1 represents the methodology filed at the FERC with New Brunswick & CSC interfaces modeled with their import capability as determined by recent ISO Transmission Planning studies

• Case 2 represents the methodology filed at the FERC but noting that protests may be filed to model the New Brunswick & CSC interfaces at 1,000 MW & 330 MW

• Case 3 represents the existing tie benefits methodology in the event that the FERC requires additional time to review the proposed Tie Benefits Calculation Methodology


DRAFT

ISO Proposed ICR Values

• The ISO proposes the ICR and Related Values associated with the Case 1 Scenario for the 2014/2015 FCA.

• These values reflect the tie benefits that are calculated according to the methodology that was filed with the Federal Energy Regulatory Commission (FERC) on December 30, 2010.

• For a copy of the FERC filing, please see:

http://www.iso-ne.com/regulatory/ferc/filings/2010/dec/er11-2580-000_12-30-10_tie_benefits.pdf


DRAFT

ISO Recommended ICR and Related Values (MW) for 2014/2015

* Total Resources for New England excludes HQICCs


2014/2015 FCANew

England ConnecticutNEMA/ Boston Maine

Peak Load (50/50) 29,025 7,585 5,805 2,185

Total Resources* 36,838 9,505 3,943 3,712

Installed Capacity Requirement 34,154

NET ICR (ICR Minus 954 MW of HQICCs) 33,200

Local Sourcing Requirement 7,478 3,046

Maximum Capacity Limit 3,702

DRAFT

Comparison of ICR Values (MW)- FCA5 Versus FCA4


* Total Resources for New England excludes HQICCs

2014/15 FCA

2013/14 FCA

2014/15 FCA

2013/14 FCA

2014/15 FCA

2013/14 FCA

2014/15 FCA

2013/14 FCA

Peak Load (50/50) 29,025 28,570 7,585 7,485 5,805 5,730 2,185 2,145

Total Resources* 36,838 36,959 9,505 9,337 3,943 3,960 3,712 3,621

Installed Capacity Requirement 34,154 33,043

NET ICR (ICR Minus HQICCs) 33,200 32,127

Local Sourcing Requirement 7,478 7,419 3,046 2,957

Maximum Capacity Limit 3,702 3,187

New England Connecticut NEMA/Boston Maine

DRAFT

Effect on ICR of Assumptions


Total

MWWeighted Forced

Outage MWWeighted Forced

OutageDemand Resources 3,130 MW 17.0% 3,603 MW 15.9% -1

Generation 31,629 MW 4.8% 31,811 MW 5.1% 65IPR 1,086 MW 0% 1,111 MW 0% -9

Imports & Sales 1,114 MW 3.4% 212.8 0.3% 47

Load Forecast 547Updated Skewness Model 387WH vs. MARS Difference 12

MW % MW %OP 4 5% VR 413 1.50% 416 1.50% -9

ICR 1,111

MW MW28,570 29,025

33,043 34,154

AssumptionEffect on ICR (MW)2013/2014 FCA 2014/2015 FCA

Tie Benefits

194 MW New York 290 MW New York

45584 MW Maritimes 439 MW Maritimes

916 MW Quebec (HQICCs) 954 MW Quebec (HQICCs)

6 MW Quebec via Highgate 6 MW Quebec via Highgate

1,700 MW 1,689 MW (Case 1)

DRAFT

ICR Scenarios


• ALCC is the “Additional Load Carrying Capability” used to bring the system to the 0.1 Reliability Criterion.

HQICCs

APk

ALCCliefReLoad4OPBenefitsTieCapacity

ICRtRequiremenCapacityInstalled

1

)(

Total Capacity Breakdown Case 1 Case 2 Case 3

Generation and Intermittant Resources 32,922 32,922 32,922

Tie Benefits 1,689 1,702 1,870

Imports/Sales 173 173 173

Demand Resources 3,603 3,603 3,603

OP 4 Action 6 & 8 - Min Res 216 216 216

Expansion Unit Capacity - - -

Capacity 38,603 38,616 38,784

Installed Capacity Requirement Calculation Details Case 1 Case 2 Case 3

Annual Peak 29,025 29,025 29,025

Capacity 38,603 38,616 38,784

Tie Benefits 1,689 1,702 1,870

HQICCs 954 966 950

OP4 - Action 6 & 8 416 416 416

Minimum Reserve Requirement (200) (200) (200)

ALCC 3,058 3,067 3,219

Installed Capacity Requirement 34,154 34,157 33,984

Net ICR 33,200 33,191 33,034

Reserve Margin w ith HQICCs 17.7% 17.7% 17.1%Reserve Margin w ithout HQICCs 14.4% 14.4% 13.8%

Tie Benefits Scenario

DRAFT

LRA/MCL Load Zone Determination

• LRA and MCL has only been calculated for the three load zones which have previously been identified as import or export constrained.


DRAFT

LRA Scenarios - Connecticut


Connecticut Zone Case 1 Case 2 Case 3

Resourcez [1] 9,505 9,505 9,505

Proxy Unitsz [2] 0 0 0

Proxy Units Adjustmentz [3] 0 0 0

Firm Load Adjustmentz [4] 1,935 2,015 1,935

FORz [5] 0.0653 0.0653 0.0653

LRAz [6]=[1]+[2]-([3]/(1-[5]))-([4]/(1-[5])) 7,434 7,349 7,434

Rest of New England Zone

Resource [7] 27,333 27,333 27,333 Proxy Units [8] 0 0 0 Proxy Units Adjustment [9] 0 0 0 Firm Load Adjustment [10] = -[4] -1,935 -2,015 -1,935

Total System Resource [11]=[1]+[2]-[3]-[4]+[7]+[8]-[9]-[10] 36,838 36,838 36,838

Local Resource Adequacy Requirement - Connecticut

DRAFT

LRA Scenarios –NEMA/Boston


NEMA/BOSTON Zone Case 1 Case 2 Case 3

Resourcez [1] 3,943 3,943 3,943

Proxy Unitsz [2] 0 0 0

Proxy Units Adjustmentz [3] 0 0 0

Firm Load Adjustmentz [4] 1,275 1,275 1,275

FORz [5] 0.0857 0.0857 0.0857

LRAz [6]=[1]+[2]-([3]/(1-[5]))-([4]/(1-[5])) 2,549 2,549 2,549

Rest of New England Zone

Resource [7] 32,895 32,895 32,895

Proxy Units [8] 0 0 0

Proxy Units Adjustment [9] 0 0 0

Firm Load Adjustment [10] = -[4] -1,275 -1,275 -1,275


Local Resource Adequacy Requirement - NEMA/BOSTON

DRAFT

LSR for Connecticut & NEMA/Boston Zones

• LSR is set by the TSA, which is higher than the LRA for both Connecticut and NEMA/Boston Zones

• Connecticut– LRA = 7,434 MW– TSA = 7,478 MW– LSR = 7,478 MW

• NEMA/Boston– LRA = 2,549 MW– TSA = 3,046 MW– LSR = 3,046 MW


DRAFT

MCL Scenarios – Maine


Rest of New England Zone Case 1 Case 2 Case 3

Resourcez [1] 33,127 33,127 33,127

Proxy Units z [2] 0 0 0

Surplus Capacity Adjustmentz [3] 3,409 3,420 3,575

Firm Load Adjustmentz [4] -5 -5 -175

FORz [5] 0.0618 0.0618 0.0618

LRAz [6]=[1]+[2]-([3]/(1-[5]))-([4]/(1-[5])) 29,498 29,487 29,503

Maine Zone

Resource [7] 3,712 3,712 3,712

Proxy Units [8] 0 0 0

Proxy Units Adjustment [9] 0 0 0

Firm Load Adjustment [10] = -[4] 5 5 175


Maine Zone Case 1 Case 2 Case 3

ICR for New England [1] 33,200 33,191 33,034

LRARestofNewEngland [2] 29,498 29,487 29,503

Maximum Capacity LimitY [3]=[1]-[2] 3,702 3,704 3,531

Local Resource Adequacy Requirement - RestofNewEngland (for Maine MCL calculation)

Maximum Capacity Limit - Maine


Questions?


Assumptions for the ICR Calculation for the 2014/15 FCA


Modeling the New England Control Area

The New England ICR are 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.


Assumptions for the 2014/15 ICR

• Load Forecast– Load Forecast distribution

• Resource Data– Existing Qualified Generating Capacity Resources– Existing Qualified Intermittent Power Capacity Resources – Existing Qualified Import Capacity Resources and Known Sales– Existing Qualified Demand Resources (DR)

• Resource Availability– Generating Resources Availability– Intermittent Power Resources Availability– Demand Resources Availability

• Load Relief from OP 4 Actions– Tie Reliability Benefits

• HQICCs• Maritimes• New York

– 5% Voltage Reduction


Load Forecast Data

• Load forecast assumption from the 2010 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.


Load Forecast Data – New England System Load Forecast

Probability Distribution of Annual Peak Load (MW)

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 95/5

2014/15 27,665 27,905 28,240 28,610 29,025 29,465 29,915 30,560 31,340 32,000

Year Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May

2014/15 25,790 29,025 29,025 23,475 18,225 19,730 22,505 22,505 21,660 20,300 17,800 20,625


Resource Data – Existing Qualified Generating Capacity Resources (MW)

• Winter Generation values shown for informational purposes, only summer values are modeled.• Intermittent Resources have both summer and winter values modeled.

GenerationSummer Winter Summer Winter Summer Winter

MAINE 3,004.048 3,232.430 261.068 348.702 3,265.116 3,581.132 NEW HAMPSHIRE 4,100.001 4,262.887 157.650 198.575 4,257.651 4,461.462 VERMONT 893.441 961.724 75.741 119.925 969.182 1,081.649 CONNECTICUT 7,993.822 8,388.406 414.569 428.405 8,408.391 8,816.811 RHODE ISLAND 2,624.615 2,942.753 5.889 8.209 2,630.504 2,950.962 SOUTH EAST MASSACHUSETTS 6,015.601 6,498.211 78.808 82.310 6,094.409 6,580.521 WEST CENTRAL MASSACHUSETTS 3,904.790 4,171.708 48.174 67.497 3,952.964 4,239.205 NORTH EAST MASSACHUSETTS & BOSTON 3,274.882 3,697.379 68.939 71.307 3,343.821 3,768.686

Total New England 31,811.200 34,155.498 1,110.838 1,324.930 32,922.038 35,480.428

Load Zone Intermittent Total


Resource Data – Existing Qualified Import Capacity Resources

• Imports modeled with tie line forced outage rates of 3% for HQ Phase II, 1 % for Highgate and 0% for New York ties.

• Total EFORd is the weighted average using the Summer Capacity.• The VJO contracts are modeled with delist bids to reflect the value of the firm contract.• MRI III.12.7.2(c) states that all Existing Import Capacity Resources backed by a multiyear contract to

provide capacity in the New England Control Area shall be modeled in the ICR calculation

Resource Name Interface

Summer Qualified

Capacity (MW)

Import Capacity Modeled in ICR

(MW) EFORd (%)

NYPA - CMR NY AC Ties 68.800 68.800 - NYPA - VT NY AC Ties 11.000 11.000 - VJO - Highgate HQ Highgate 212.000 194.000 1.0 VJO - Phase I/II Phase I/II 50.000 39.000 3.0 Lievre River Project - Import Phase I/II 240.000 - - Erie Boulevard Hydropower - Import NY AC Ties 697.000 - -

Total Imports 1278.800 312.800 0.3


Resource Data – Known Sales (MW)

• Modeled as removed capacity from the resource supplying the export.

Export Summer Winter LIPA over Cross Sound Cable 100.000 100.000


Resource Data – Existing Qualified Demand Resources (MW)

• The DR capacity modeled in the ICR is the Summer Existing Qualified DR Capacity by Load Zone for FCA5.

• The Qualified Capacity rating of DR 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 112.206 109.607 - - 311.220 327.291 35.023 32.519 458.449 469.417NEW HAMP SHIRE 70.963 70.346 - - 59.449 58.640 39.135 37.191 169.547 166.177VERMONT 94.398 93.620 - - 51.060 60.148 18.240 17.268 163.698 171.036CONNECTICUT 122.044 116.709 301.055 301.055 370.481 334.606 300.301 284.386 1093.881 1036.756RHODE ISLAND 83.349 82.346 1.727 1.727 74.931 64.750 98.478 87.081 258.485 235.904SOUTH EAST MASSACHUSETTS 130.221 127.964 1.727 1.727 165.573 149.330 78.637 66.533 376.158 345.554WEST CENTRAL MASSACHUSETTS 116.486 113.984 30.420 30.420 169.213 146.302 101.193 86.703 417.312 377.409NORTH EAST MASSACHUSETTS & BOSTON 236.207 233.245 - - 285.866 252.933 143.624 123.330 665.697 609.508

Total New England 965.874 947.821 334.929 334.929 1487.793 1394.000 814.631 735.011 3603.227 3411.761

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

DRAFT

Resource Data Used in the LRA Calculation (MW)


Type of Resource New England Connecticut NEMA/Boston Maine

Generating Resources 31,811.200 7,993.822 3,281.422 3,004.048

Intermittent Power Resources 1,110.838 414.569 70.054 261.380

Demand Resources 3,603.227 1,096.249 591.703 446.126

Import Resources 312.800 - - -

Total MW Modeled in LSR and MCL 36,838.065 9,504.640 3,943.179 3,711.554

Load Forecast 50/50 29,025 7,585 5,805 2,185


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 (September 2005 – August 2010) of

generator submitted Generation Availability Data System (GADS) data

– NERC GADS Class average data will be used for immature units

• Scheduled Outage Assumption– Each generating unit weeks of Maintenance modeled– Based on a 5-year average (September 2005 – August 2010) of

each generator’s actual historical average of planned and maintenance outages scheduled at least 14 days in advance

– NERC GADS Class average data will be used for immature units


Availability Assumptions - Generating Resources

• 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 11,407 4.2 5.3

Fossil 9,421 7.7 4.3

Nuclear 4,630 1.8 3.0Hydro(Includes Pumped Storage) 3,073 3.0 3.3

Combustion Turbine 2,915 6.7 1.9

Diesel 232 6.7 1.0Miscellaneous 133 14.4 1.2

Total System 31,811 5.1 4.1


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.

DRAFT

Availability Assumptions - Demand Resources

• DR Performance analysis calculated for the FCA4 ICR• Applied to Existing Qualified DR for FCA5


Load ZoneSummer

MWPerformance

%Summer

MWPerformance

%Summer

MWPerformance

%Summer

MWPerformance

%Summer

MWPerformance

%

MAINE 112.206 100 - - 311.220 100 35.023 100 458.449 100NEW HAMP SHIRE 70.963 100 - - 59.449 74 39.135 74 169.547 85VERMONT 94.398 100 - - 51.060 99 18.240 45 163.698 94CONNECTICUT 122.044 100 301.055 100 370.481 76 300.301 87 1093.881 88RHODE ISLAND 83.349 100 1.727 100 74.931 48 98.478 17 258.485 53SOUTH EAST MASSACHUSETTS 130.221 100 1.727 100 165.573 56 78.637 58 376.158 72WEST CENTRAL MASSACHUSETTS 116.486 100 30.420 100 169.213 67 101.193 72 417.312 80NORTH EAST MASSACHUSETTS & BOSTON 236.207 100 - - 285.866 72 143.624 87 665.697 85

Total New England 965.874 100 334.929 100 1487.793 76 814.631 73 3603.227 84

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

DRAFT

Transmission Interface Limits Modeled in LRA


• CT Import updated to reflect the impact of the Greater Springfield Reliability Project• Boston Import does not reflect the permanent de-list of the Salem Harbor station• Maine-New Hampshire transfer limit does not reflect the impact of the Maine Power

Reliability Project as it has not been certified to be in-service prior to FCA5

Interface Limit (MW)Connecticut Import 2,600Boston Import 4,900Maine-New Hampshire 1,600


OP 4 Assumptions - Tie Reliability Benefits

• Modeled with Forced Outage assumptions of 3% for Québec, 1% for Maritimes, and 0% for New York due to tie line availability.

MW

1689

439

Highgate 6

Phase II 954

AC Ties 290

CSC 0

1702

442

Highgate 6

Phase II 966

AC Ties 202

CSC 86

1870

709

Highgate 6

Phase II 950

AC Ties 205

CSC 0

Tie Benefits Scenario

Case 3: Existing Methodology; New

Brunswick Import at 1000MW; CSC at 330

MW;

Total Tie BenefitsMaritimes CA

Quebec CA

New York CA

Case 2: ISO Proposed Methodology; New

Brunswick Import at 1000MW; CSC at 330

MW; Internal Constraints Modeled


Quebec CA

New York CA

Case 1: ISO Proposed Methodology; New

Brunswick Import at 700MW; CSC at 0 MW;

Internal Constraints Modeled


Quebec CA

New York CA

DRAFT

OP 4 Assumptions - Action 6 and 8 Voltage Reduction (MW)

• 1.5% OP 4 Appendix A assumption developed by ISO Operations• Calculated as (Peak Load MW – Passive DR MW) * 1.5%


Peak Load Passive DR

Action 6 & 8 5% Voltage Reduction

Jun - Sep 29,025 1,301 416

Oct - May 22,505 1,283 318

DRAFT

Tie Benefit Scenarios Summary of ICR Resources (Summer MW)


• Notes: Generating Resources is the summer Qualified Capacity values. Intermittent Power Resources have both the summer and winter capacity values modeled.

• Demand Resources is the Summer Qualified value which includes the Transmission & Distribution gross-up. • Import Resources are modeled with the value of the firm VJO contract reflected.• OP 4 Voltage Reduction includes both Action 6 and Action 8 MW assumptions. • Minimum Operating Reserve of 200 MW is the minimum Operating Reserve requirement for transmission system

security.

Type of Resource Case 1 Case 2 Case 3

Generating Resources 31,811.200 31,811.200 31,811.200

Intermittent Power Resources 1,110.838 1,110.838 1,110.838

Demand Resources 3,603.227 3,603.227 3,603.227

Import Resources 312.800 312.800 312.800

OP 4 Voltage Reduction 416.000 416.000 416.000

Minimum Operating Reserve (200.000) (200.000) (200.000)

Tie Benefits Including HQICCs 1,689.000 1,702.000 1,870.000

Total MW Modeled in ICR 38,743.065 38,756.065 38,924.065


Questions?

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