TEAC20

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TEAC20

Thursday, March 4, 2004

Sheraton Hotel

Springfield, Massachusetts

REDACTED VERSION FOR POSTING

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TEAC20 Agenda

• Welcoming Remarks• FDWG Update• Transmission Planning Study Updates

CT Area Issues ME-NH issues NB-NE Tie Performance

• Generator Clutch Technology• NEPOOL Project List Process

• ISO/RTO Planning Coordination Protocols• RTEP04 Planning Assumptions• RTEP04 Resource Adequacy Analysis

Assessment CasesPreliminary Case Results

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Fuel Diversity Working Group

TEAC20 PresentationMarch 4, 2004

Mark Babula ISO-NEPower Supply & Reliability

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Fuel Diversity Working Group

• In response to the events of January 2004, ISO-NE is proposing to reconstitute the FDWG with respect to changing:

– Name change to address specific gas & electric issues– Existing Mission Statement & Charter– Broaden the Scope– Requesting increased participation from:

• New England utility and environmental regulators• Natural gas industry• Interested stakeholders & market community

• The newly transformed Electric Gas Working Group (EGWG) will address both near and long term issues.

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Electric Gas Working Group

• The newly transformed Electric Gas Working Group (GEWG) will address:

– The results and findings of ISO-NE’s Cold Snap report• Short-term issues – Resolve by Winter 2004/05• Long-term issues – TBD and coordination with RTEP

– Additional areas of investigation as suggested from stakeholders

– Liaison to regional and national committees on changing existing or developing new policy thru regulatory means• NERC GEITF (Gas/Electricity Interdependency Task

Force)• NAESB GECTF - North American Energy Standards Board

– (Gas Electric Coordination Task Force)

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Electric Gas Working Group

• The Electric Gas Working Group (GEWG) should work to coordinate the education and understanding of both gas & electric systems through:

– Cross training of electric & gas system operators– Establishing emergency communications protocols

& procedures– Assess and address system restoration issues– Assess coordination of electric & gas system

maintenance requirements

– Address other common issues

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Announcement

• FDWG next meeting Mass Electric Auditorium, Northborough, MA – March 19th - 9:30 a.m. to 4:00 p.m.

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Transmission Planning Study Updates

Rich Kowalski

ISO-NE

System Planning

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Eastern ConnecticutSystem Performance

Concerns

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Area Characteristics

• Existing Area Load: 700 to 750 MW

• Basically three feeds into area:• Montville Substation – two 345-115kV

autotransformers and approximately 750 MW of generation

• Card Substation – one 345-115kV autotransformer

• 115kV tie to Rhode Island

• About 90 MW of local generation

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Performance

• Several probable contingencies result in severe thermal overloads and unacceptable voltages (bordering on voltage collapse)

• SPS currently in place for loss of the Sherman Road to Lake Road 345kV line

• Issues surrounding the location ‘electrically’ of the Lake Road Plant

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CIRCUIT DIAGRAM REDACTED

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Alternatives Studied

• Various line taps, line reconductorings and 69 to 115kV conversions

• 345kV breaker additions

• Various 115kV line additions

• Various autotransformer additions – Brooklyn, Tracy and/or Lake Road

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Preferred Plan

• Add 345-115kV autotransformer at Tracy

• Add 345kV circuit breaker at Card

• Benefits:– Relieves all thermal overloads– Acceptable voltages for all contingencies but

one borderline consideration– Quick fix without requiring line additions

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Current Status

• Draft Thermal / Voltage report in Task Force review stage

• Transfer Analysis to be completed

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Connecticut ImportReinforcement Study

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Background

• Previous analyses have shown:– Interdependence of transfer capabilities for

SEMA/RI Export, East-West & CT Import Interfaces

– Transfers through these 3 interfaces contribute to heavy loadings on the same key transmission facilities

– The resource-rich area to the east of Connecticut is currently the best source for Connecticut.

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System Performance

• RTEP03– With respect to CT Import Area Capacity,

“… Connecticut is at risk in 2003. Operating deficiencies could occur as a result of a higher than normal peak load. It also shows the likelihood of this deficiency occurring for more typical ‘reference’ load as early as 2006.”

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RTEP03 Recommendation

• “Transmission planning studies should be completed to support the development and implementation of a 345kV line from Millbury to Card.”

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GEOGRAPHICAL AREA:

Connecticut Import Reinforcement Project

CIRCUIT DIAGRAM REDACTED

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Study Plan & Status

• ISO / TO Working Group established

• Scope of work / Schedule developed

• Various meetings and teleconferences held

• Comprehensive list of alternatives developed

• Target completion August 2004

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Summary Of Alternatives

• Marine ties from Long Island, SEMA or RI through the Sound

• Ties from New York State – Pleasant Valley area

• Different over land routes from SEMA/RI (both AC and DC)

• Western Mass to CT

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Maine – New HampshireTransmission System Studies

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ME-NH Transmission Technical Issues List Heavy load growth in Maine and NH Seacoast

areas

Central and southern New Hampshire reliability assessment

Complex operating limits/dependencies for voltage and stability on Maine-New Hampshire Interfaces

Maine and NH reliability assessments for long-term autotransformer outages

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ME-NH Transmission Technical Issues List Closing Y138 between Western Maine and

Central New Hampshire

Poor performance for several stuck breaker contingencies in Maine (Buxton and Surowiec)

Western Maine stability limit definition

Seabrook Uprate - reduction in generator reactive capability and new excitation system

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Need to Coordinate the Studies of ME-NH Issues

• Interdependence of issues and solutions

• Comprehensive analysis of larger area

• Development of coordinated plans

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Need to Coordinate the Studies of ME-NH Issues

• Broader range of ideas, solutions, and approaches

• Enhancements for future reliability for load and generation in this region

• Support effective use of transmission facilities across all Northern New England (NNE) interfaces

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First Priority Studies• Maine Reliability Assessment – Schedule TBD

– Long-term autotransformer outages– Address seacoast area

• New Hampshire Reliability Assessment – Schedule TBD– Long-term autotransformer outages– Address seacoast and central/southern areas

• Additional transformation possibly at Deerfield, Newington, etc.

• Impact of Seabrook Up-rate

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Second Priority Studies• Maine-New Hampshire Reliability Project–

In progress– Address complex operating

limits/dependencies for ME-NH– Address performance concerns associated

with ME stuck breakers • Currently three alternatives tested• Is being coordinated with the Closing Y-138

Project• Impact of Seabrook Up-rate

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Second Priority Studies• Closing Y-138 Project– In progress

– Address central New Hampshire reliability– Should improve Western Maine stability/voltage

performance– Some increase in Maine-New Hampshire transfer

capability• Alternative development almost complete, reactive needs

outstanding• Is being coordinated with Maine-New Hampshire Reliability

project • Will be coordinated with Western Maine Stability assessment

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Second Priority Studies

• Western Maine Stability Assessment– Schedule TBD– Assess the stability performance of the western Maine

transmission system• Will be coordinated with the Closing Y-138 Project.

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NNE Transmission Corridor

• CIRCUIT DIAGRAM REDACTED

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Maine-New Hampshire Reliability Project Report on 2003 Studies

Investigated three alternatives:

1. Add a dynamic voltage control system (SVD) at Deerfield S/S with a 500 – 600 MVAr capability.

2. Interconnect Section 391 at Deerfield S/S and add three breakers at Buxton for the re-termination of Section 386.

3. Add a dynamic voltage control system (SVD) at Deerfield S/S with a 500 – 600 MVAr capability and interconnect Section 391 at Deerfield S/S and add three breakers at Buxton for the re-termination of Section 386.

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Conclusions of Maine – New Hampshire Reliability Project Alternative Assessments

Alternative #1 Insufficient benefit

for Maine and NH system reliability to

justify its high cost.

Alternative #3 Best method to

mitigate reliability issues but high cost.

Significant improvement in voltage, thermal, and stability transfer limits; mitigation of dependencies

Provides dynamic voltage support along NNE 345kV corridor.

Alternative #2 Increases transfer

limits as well for a much lower cost.

Elimination of stuck breaker contingencies is significant benefit to NNE reliability.

Looping Section 391 into Deerfield increases electrical performance of bulk power system.

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Transfer Limits from Maine – New Hampshire

Reliability Project Analysis

2600 to 28002350 to 27002375 to 2725StabilityPlanningCriteria

Alt. 3Deerfield SVD

& 391 & Buxton Breakers

(MW)

Alt. 2Deerfield 391 & Buxton Breakers

(MW)

Alt. 1Deerfield SVC

(MW)

ExistingSystem(MW)

NNE Scobie plus 394 Interface Limits

>1800162517001550Stability

1550 to 16001525 to 15751375 to 14251375 to 1425Thermal

1600 to 17001350 to 14501225 to 13001100 to 1300VoltageOperatingCriteria

>1800162517001550Stability


1550 to 16501250 to 13001050 to 1175775 to 975VoltagePlanningCriteria

$34M$9M$25MCost

Alt. 3 -Deerfield SVD


(MW)

Alt. 2 -Deerfield 391 & Buxton Breakers

(MW)


(MW)

ExistingSystem(MW)

ME-NH Interface Limits

2600 to 28002350 to 27002375 to 2725StabilityPlanningCriteria

Alt. 3Deerfield SVD


(MW)

Alt. 2Deerfield 391 & Buxton Breakers

(MW)

Alt. 1Deerfield SVC

(MW)

ExistingSystem(MW)

NNE Scobie plus 394 Interface Limits

>1800162517001550Stability


1600 to 17001350 to 14501225 to 13001100 to 1300VoltageOperatingCriteria

>1800162517001550Stability


1550 to 16501250 to 13001050 to 1175775 to 975VoltagePlanningCriteria

$34M$9M$25MCost



(MW)

Alt. 2 -Deerfield 391 & Buxton Breakers

(MW)


(MW)

ExistingSystem(MW)

ME-NH Interface Limits

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Studies have concluded the following system upgrades are required for closing Y138:

Phase Shifter on B112 Re-tension Section 214 Beebe B112 Terminal Upgrades Add 2 breakers at Saco Valley Add 50 MVar at Kimball Road Add 22 MVar at White Lake (7 and 15 MVar)

Closing Y138 Report on 2003 Studies

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Status of Y138 Closing Project

• Final design studies being conducted• Local area impacts on sub-transmission

networks being analyzed• Preparing to conduct 18.4 Level III Steady-state

and Stability Assessments • 18.4 approval estimated for 3rd quarter 2004

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Example of Benefits to Coordinating Studies

In 2003, two studies were completed with different individual objectives.

Maine-New Hampshire Reliability Project• ME-NH transfer capability improvement• Eliminate complex operating guides for voltage and

stability

Closing Y138• Improve central New Hampshire reliability• Relieve congested Maine transmission interfaces

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Combination of Projects from each Study Analyzed Together

Maine-New Hampshire Reliability Project Alternative #2 and Closing Y138 Study were analyzed together for voltage limits based on operating criteria. Preliminary increases to Maine-New Hampshire transfer are shown below:

ME-NH Voltage/Reactive Transfer Limit (MW)

Existing System 1100-1300

Alternative #2 ($9M) 1350-1450

Alternative #3 ($34M) 1600-1700

Alternative #2 with Y138 Closed ($19M)

1600-1800

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Coordinated Solution

• Need to assess S. New Hampshire requirements• Assess impact of potential combined solutions• Develop a comprehensive plan

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New Brunswick-New England/MEPCO Area

System Performance Concerns

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Region Characteristics

• The Maritimes are synchronously connected to the Eastern Interconnection by only the 150 mile long, 345 kV Orrington to Keswick Line.

• There is a single 345 kV path from Orrington to Maine Yankee with a limited number of 115 kV parallel paths.

• This electrically weak corridor requires 8 SPS. (MY DCT, Maxcy’s Cross-trip, Bucksport Over-current, Bucksport Reverse Power, 396, GCX, Loss of Export on 396, KPR (if Chester SVC is OOS))

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Region Characteristics

• New Brunswick–New England transfer capability is 700 MW.

• New England-New Brunswick transfer capability ranges from +/-250 MW. (Some conditions require a minimum import from NB)

• Orrington South transfer capability is approximately 1,050 MW.

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CIRCUIT MAP REDACTED

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New England System Concerns

• Consequences of large Maritime Provinces load loss (reason for Keswick GCX SPS)

• Keswick GCX SPS inadvertent operation• L/O 1200+ MW due to trips/inadvertent trips

of Keswick-Orrington 345 kV (NB-NE tie Section 396), Orrington-Maxcys 345 kV (Section 388), Maxcys-Maine Yankee 345 kV (Section 392)

• L/O 396 SPS (trips Maine Independence Station) (contributes to L/O 1200+ MW)

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New England System Concerns

• Orrington-So. 1050 MW limit • MY DCT outage• CMP transient voltage response• NB-NE tie losses• Limited access of MPS/EMC to New England

resources (no direct ties to the New England transmission system)

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New Brunswick System Concerns

• Consequences of large Maritime Provinces load loss (reason for Keswick GCX SPS)

• New Brunswick Power desires a more secure inter-Area interconnection with New England.

• New Brunswick Power desires a firm import capability from New England.

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New Brunswick System Concerns

• NB-NE tie losses• New Brunswick Power is interested in

improved market access between NPCC/NEPOOL and the Maritime Control Area.

• The Maritimes are winter peaking while New England is summer peaking. Improved transfer capability would allow for better utilization of existing generation resources.

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Alternatives Under Consideration(None individually address all concerns)

• Replace/Redesign GCX SPS [$?](Mar. Prov. l/o ld)

• Northeast Reliability Interconnect Project (2nd NB tie: LePreau-Orr. 345 kV) [$80M](MP l/o ld, GCX, 396 trip, 396-MIS SPS (?), CMP t.volt, NB-NE tie losses,

impr. MPS/EMEC access, NB benefits)

• Thyr.-Contr. Series Comp. (TCSC) in Keswick-Orrington 345 kV [~$25M](MP l/o ld, GCX (?), 396-388-392 trip, 396-MIS SPS (?), CMP t.volt (?))

• Orrington-Maxcys 345 kV fixed series compensation* [$13.5M](Or-S 1050MW)

• Reconductor Bucksport-Highland 115 kV Line, western Maine capacitors [$5M](Or-S 1050MW)

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Alternatives Under Consideration(None individually address all concerns)

• Split MY DCT [~$12M](MY DCT outage)

• MY DCT SPS to trip NB generation* [~$0.5M](MY DCT outage)

• MEPCO SPS redesign [$0.5M-$5M](CMP t.volt)

• Northern Maine Interconnection Project – 115 kV [$13.6M](MPS access)

*Part of 2nd NB tie project

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Potential Additional Benefits of Northeast Reliability Interconnect Project

(2nd NB tie: LePreau-Orrington 345 kV)• Strengthens a section of a very weak 345 kV

path• Reduces contingencies that separate Maritimes

Provinces from Eastern Interconnection• Increases NB to Orrington capability from 700

MW to 1000MW• Increase in resource capacity available to New

England (Orrington; S. ME with Orrington-Maxcys series comp.)

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Potential Additional Benefits of Northeast Reliability Interconnect Project

(2nd NB tie: LePreau-Orrington 345 kV)

• Increase in energy available to New England (Orrington; S. ME with Orrington-Maxcys series comp.)

• Increased New England-New Brunswick transfer capability could provide opportunities for locked-in generation in Maine.

• Future potential for increased sharing of ancillary services with New Brunswick.

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Potential Alternative Configurations of theNortheast Reliability Interconnect Project

• 2nd NB tie: LePreau-Orrington 345 kV [$80M on US side, $40M on Can. Side]

• Up-rate existing Orrington to Keswick 345 kV[$?]] – Also requires Orrington-South & MY DCT reinforcements– Would increase magnitude of L/O source contingencies– If feasible, would likely require substantial combinations of

fixed/dynamic series/shunt reactive compensation

• Convert existing Orrington to Keswick 345 kV Line to HVDC. [~$200M] – Also requires Orrington-South & MY DCT reinforcements.– Would increase magnitude of L/O source contingencies– Would create a small Maritime Province asynchronous system; L/O

source and load contingencies would be very problematic

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Potential Alternative Configurations of theNortheast Reliability Interconnect Project

• LePreau-Orrington 500 kV [$?]– Also requires Orrington-South & MY DCT reinforcements.– Might eliminate need for one of the project SPSs and series

compensation– Canadian side permitted for 345 kV construction

• LePreau-Maxcys (further south?) 500 kV [$?]– Also requires MY DCT reinforcements– Might eliminate need for one of the project SPSs and series

compensation– Might eliminate trip issues– Canadian side permitted for 345 kV construction

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Summary of Possible Solutions Alternative

Prob./Issue

NRIP 345 kV: Orrington-Lepreau 345 kV

388 Series Comp* 86 Recond. & ME caps.

MY Dct SPS*

Split MY Dct

TCSC No. ME IP 115 kV

LePreau - ? 500 kV

MP Ld loss (GCX redesign)

Tech. solution Tech. sol. demo Need detailed analysis

Probably

396 trip Tech. solution Tech. sol. demo Need detailed analysis

Probably

388/392 trip Tech. sol. demo Need detailed analysis

Possibly (Past Orr.)

MIS L/O 396 SPS

Tech. sol. demo Need detailed analysis


Probably

Orr-So.150 MW increase

Tech. sol. Study Reliability

& Economic benefit


Study Reliability & Economic benefit

Possibly (Past Orr.)

MY DCT outage Tech. sol. Tech. sol. Possibly (Past ME Ynk)

CMP trans. volt Tech. solution Tech. sol. demo Need detailed analysis

Probably

NB-NE loss savings

Quantify Quantify

NB-NE 300 MW & Orr-So. 150 MW increase

Tech. solution Study Reliability & Economic benefit

Same as 345 kV

MPS benefit Tech. sol. demo Need detailed analysis

Study benefit

Tech. sol. Same as 345 kV

EMEC benefit Tech. sol. demo Need detailed analysis

Study benefit

Same as 345 kV

* Required with NRIP 345 kV

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Summary of Remaining Analyses• Orrington-South 150 MW limit increase

– Reliability & Economic analysis

• NRIP 345 kV - 2nd NB tie: LePreau-Orrington 345 kV – Study supplemental TCSC to address 388 & 392

trip– Verify that MIS-L/O 396 SPS can be eliminated– Evaluate loss reduction– Reliability & Economic analysis (w/Orrington-South

150 MW increase)

• TCSC– Study with “detailed” models

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Summary of Remaining Analyses• CMP/MEPCO SPS redesign

– Finish design review and analysis

• EMEC Interconnection• NE-NB Transfer Capability

– Evaluate “Firm” NE export capability

• NB Benefits

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Operating Large Generators as Synchronous Condensers

Presented byDave Bertagnolli – ISO-New England

TEAC20March 4, 2004

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Synchronous Generator Idea

Disconnect the turbine from the generator

Accelerate the generator to synchronous speed

Connect it as synchronous condenser

System impact study required

(contributes to short circuit current)

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BenefitsGet all the voltage/stability benefits without the

energy

Could re-connect turbine when MW’s are needed

Short implementation time (6 months)

Supports Fuel Diversity

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Capital Costs

Low cost compared to alternatives:

$2 million for Clutch & misc. equipmentVs.

$20+ million for Statcomm

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ProgressPresented to TTF/TWG September 2002

Visited several plants in New England:WF Wyman, Newington Steam, Schiller, Middletown,

Millstone

Other candidate units:Mystic, Bridgeport

All generating stations are “open” to the idea

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Significant issues

Who benefits?

Who pays?

Under NEPOOL discussion

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RTEP03 - April ‘04 Update

Issue Date: April, 2004

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Introduction & Background

It is our objective in 2004 to formalize interim planning activity in order to improve the communication of ‘Plan’ progress, provide a process for interim approvals (should this be necessary), and maintain visibility of system needs.

We will be pursuing an improvement to the quality of update information, enhancing the management of change associated with the Plan, and publishing updated information as a service to our stakeholders.

To facilitate the internal and external review of our April ‘04 update, we have highlighted changes to the Project Listing, provided an analysis of changes since the RTEP03 approval, and included progress summaries on high-profile projects.

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Introduction & Background (cont’d)

We will update and publish the system plan and associated project listing on a periodic basis in 2004 (shown below). This document represents our April ‘04 update.

J

2004

F M A M J J A S O N D

RTEP-031st ‘04 Update

Apr ‘04

RTEP-032nd ’04 Update

Jul ‘04

RTEP-041st Update

Oct ‘04

RTEP-04ApprovalPeriod

RTEP-04‘Board Draft’

RTEP-04TEAC ‘Draft’

2005

RTEP-041st ’05 Update

Apr ‘05

SeptemberPublic Mtg

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The Interim Update Process

TOs UpdateProjectListing

ISO-NE Inte-grates Informa-tion & AnalyzesChanges

ISO-NE Conducts Follow-up

ISO-NE PreparesDraft UpdateReport

TEAC & RC Forward anyMajor Issues toISO-NE prior to meeting

ISO-NE PreparesResponses

ISO-NERevises theUpdate as Necessary

IntroduceProcessTo TOs

UpdateRequest &Guidelineto TOs

01/13/04 01/16/04

‘Draft’Providedto TEAC/RC

02/23/04

TEAC & RCReview ‘Draft’Update Report 02/26/04

Responsesto TEAC& RC

Presentat RC &TEAC Mtgs

Prior to meeting

03/02/04 &03/04/04

SubmitApril ‘04

Joint TO/ISO-NE Update

TEAC & RC Review

System OperatorApproval

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Requested Review Actions

TOs: Verify project information previously provided to ISO-NE staff.

TEAC & RC: Review this interim plan. Recognize system needs, and where applicable, identify market responses and/ortransmission alternatives.

System Operator: Approve and publish the interim plan.

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Contact Information

TEAC members should forward any major issues to the following address by March 11th:

[email protected]

Please check and review the latest Project Listing at:

www.iso-ne.com/committees/Transmission_Expansion_Advisory_Committee/protected/

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Glenbrook STATCOM 3.6(3 projects)

Boston Import 7.6(12 projects)

Monadnock 44.9(14 projects)

Canton-N.Bloomfield Term. 6.9

Scobie Station Rebuild 3.0

Other (aggregate) 0.4(7 projects)

Make-up of the aggregate cost estimate change between the RTEP03 November publication and the February, 2004 progress update:

April ‘04 Change Highlights (cont’d)

+ $66.4 Million

Project $ Change (millions)

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New Brentwood 115 kV Substation Reliability need – provide(Southwest New Hampshire) capacity to supply load

Upgrade Garvins 115 kV Substation Reliability need to meet (Southeast New Hampshire) compliance requirements

New Colburn St. 115/13.8 kV Substation Reliability need – provide (Boston) capacity to supply load

Second 115/13.8 kV Dover Substation Reliability need – provide (Boston) capacity to supply load

Pequonnock 115 kV Substation Bus Upgrade Substation Equipment Bracing & Ground Grid Upgrade to Higher Short Circuit Capability(Southwest Connecticut)

Five (5) new Projects and Corresponding Needs (*):

April ‘04 Change Highlights (cont’d)

Project Need

(*) Projects may have some non-PTF components

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Draft Northeastern ISO/RTO Planning

Coordination Protocol

Mike HendersonISO-New EnglandSystem Planning

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• Coordinates system planning activities• Establishes

– Inter-Area Planning Stakeholder Advisory Committee

– Joint ISO/RTO Planning Committee

• Data and information exchange• Coordinates Tariff studies• Northeastern coordinated system plan• Dispute resolution

Draft Northeastern ISO/RTOPlanning Coordination Protocol

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• ISO/RTO draft protocol developed– Full participation by PJM, NYISO, and ISO-NE– Limited participation by the IMO, TransEnergie Quebec, and New Brunswick

• Stakeholder review of draft protocols– New England– Jointly, if required

• Cost responsibility for planning activities– Studies

• Tariff studies – customer• Northeastern coordinated plan – each party

– Administrative• Load ratio• Stakeholder meetings• Web site

• Cost responsibility for network upgrades– Process to be developed consistent with the provisions of each area’s Tariff

Next Steps . . .

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Draft Northeastern ISO/RTO Planning Coordination Protocol

ITEM PAST RECENT

IMPROVEMENTS DRAFT PROTOCOL COMMENTS Coordination of System Plans

NPCC review of individual area assessments for inter-area impacts

Better informal coordination with NY

Joint studies to ensure individual area plans are well coordinated

Identification of improvements required for reliability.

Study process similar to NE’s including stakeholder group

Coordination of data, timelines, scopes of work, etc. will greatly improve inter-area planning

Approvals are subject to each region’s planning procedures.

Tariff Studies NPCC review of individual area assessments for inter-area impacts

Better informal coordination with NY

Recognizes different interconnection requirements

Early notification of inter-area impacts

Payment for full scope of work that considers inter-area issues

Web site listing queue of projects with potential inter-area impacts

Network upgrades identified as part of the SIS under terms and conditions of potentially impacted system consistent with FERC and regulatory policy

Customers understand inter-area impacts at earliest possible date.

Customers to address remote area upgrades as a requirement of interconnection.

Many issues to be addressed by JIPC with input from stakeholders.

Cost Allocation for Projects with Inter-Area Impact

Consistent with each area’s Tariff, including negotiated agreements. FERC is the ultimate arbitrator.

Earlier identification of issues achieved through informal coordination

Cost of elements of the Northeastern Coordinated System Plan (NCSP) and Tariff studies will be addressed consistent with provisions of each area’s Tariff.

Allows for smooth transition to RTO-NE.

No obligation for remote system to make NCSP improvements for neighbor. Will require further evolution.

2/23/04 4

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• Current Process– ISO-NE comments on interconnection plan will be

conveyed to NYISO prior to NY stakeholder review. These will include a scope of work for testing the NEPOOL system.

– Impacts on NEPOOL system considered at New York Stakeholder meetings?

– Impacts on NEPOOL system considered at New York State licensing process?

– Impacts on NEPOOL system considered at NPCC? (While NPCC decisions are non-binding, NPCC is an important forum.)

– Impacts considered by FERC?

Example: Interconnection Project in NY

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• Draft Protocol– NYISO advises ISO-NE of the interconnection application.– ISO-NE provides NYISO with scope of work and estimated

cost of studies of the New England system. ISO-NE can participate in studies.

– Under the NYISO agreement with the interconnection customer, any impacts on the New England system will be addressed in the NYISO interconnection studies.

• Impacts on the New England system to be determined in accordance with ISO-NE procedures and criteria. Needed network upgrades on the New England system to be identified in the NYISO system impact study.

Example: Interconnection Project in New York (cont.)

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Planning Protocol Input

• Please provide comments on draft planning protocol by March 12th.

• Comments received to date:– NEPOOL Information Policy Compliance– NPCC Role

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RTEP04 Planning Assumptions

• Load Forecast • Issues Raised at TEAC19• Information updated

• Fuel Prices

• Emission Allowances

• Control Area Imports/Exports

80

NSTAR Provided Updated Forecast Growth Rates for BECO and Commonwealth Electric:

•Increased Boston Sub-area Summer Peak by 40 MW and SEMA by 30 MW in 2013

•Decreased CMA/NEMA Summer Peak by 25 MW and W-MA by 30 MW in 2013

81

Summer Peak Impacts of NSTAR Peak Growth Rate Changes on 2004 Forecast of RTEP Sub-areas

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

BOSTONRevised 5185 5310 5440 5505 5570 5630 5695 5765 5855 5920 5980Original 5195 5320 5445 5500 5555 5610 5665 5730 5820 5885 5940DIFFER -10 -10 -5 5 15 20 30 35 35 35 40

CMA/NEMARevised 1660 1700 1735 1750 1765 1780 1795 1815 1845 1865 1885Original 1660 1700 1740 1760 1775 1790 1810 1835 1865 1890 1910DIFFER 0 0 -5 -10 -10 -10 -15 -20 -20 -25 -25

W-MARevised 1945 1980 2020 2030 2040 2050 2065 2080 2100 2115 2125Original 1945 1980 2025 2040 2055 2070 2085 2100 2125 2140 2155DIFFER 0 0 -5 -10 -15 -20 -20 -20 -25 -25 -30

SEMARevised 2550 2620 2685 2715 2745 2780 2810 2855 2910 2950 2990Original 2540 2610 2670 2705 2735 2765 2800 2840 2890 2925 2960DIFFER 10 10 15 10 10 15 10 15 20 25 30

RIRevised 2295 2345 2400 2430 2460 2490 2520 2555 2595 2630 2655Original 2295 2345 2405 2430 2465 2495 2530 2565 2600 2640 2665DIFFER 0 0 -5 0 -5 -5 -10 -10 -5 -10 -10

82

Reviewed Own and Coincident Summer Peak Relationship for the New England States, 2000-2003

For Most States Own Peak the Same or Only Marginally Higher

Own and Coincident Peaks Tend to Converge Under Extreme Weather Conditions

83

Effects of Non-Coincidence Are Negligible

Percent Difference Between Own and Coincident Summer Peak Loads by State 2000-2003

Extreme Weather Impact2000 2001 2002 2003Average on Peak Forecast

CT 0.6 0.0 1.0 0.1 0.4 6.4ME 3.6 1.8 0.9 0.3 1.6 4.2MA 0.0 0.0 0.0 0.0 0.0 6.0NH 0.7 0.0 0.0 2.1 0.7 7.9RI 3.5 0.0 0.0 0.0 0.9 6.2VT 3.6 2.3 1.3 4.2 2.8 5.3

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Fuel Price Assumptions

• Fuel Price Forecast Based on Energy Information Administration’s forecast

• January 2004 Short Term Energy Outlook (STEO) for 2004, 2005– “Reference Case” forecast was used

• Dec 2003 Annual Energy Outlook (AEO) for 2006 through 2013

85

RTEP 04 AssumptionsRelative Fuel Price Forecast

2004Annual Energy Outlook Blended With Short-Term Outlook (Jan. 2004)

0.001.002.003.004.005.006.007.008.00

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

Fu

el P

ric

e (

$/M

Btu

)

Distillate Fuel (FO2) Residual Fuel (FO6)

Natural Gas Steam Coal

86

RTEP 03 AssumptionsRelative Fuel Price Forecast

2003Annual Energy Outlook Blended With Short-Term Outlook

0.001.002.003.004.005.006.007.008.00

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020F

ue

l Pri

ce

($

/MB

tu)

Distillate Fuel (FO2) Residual Fuel (FO6) Natural Gas Steam Coal

87

Comparison of Fuel Price Assumptions

Fuel Price ComparisonRTEP04 Forecast - RTEP03 Forecast

-1.50

-1.00

-0.50

0.00

0.50

1.00

1.50

2.00

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

Years

Pri

ce D

iffe

ren

ce (

$/

MM

Btu

)

Distillate Fuel (FO2) Residual Fuel (FO6)

Natural Gas Steam Coal

88

RTEP04 Fuel Price Assumptions

• Earlier RTEP efforts considered the commodity cost of fuel

• Seeking TEAC input on including fuel transportation costs– Residual Oil– Natural Gas– Coal

89

Emission Allowances

• Past RTEP economic studies did not account for emission allowances as a component of fossil unit production cost.

• Further consideration along with the changing dynamics of the allowance markets suggest these generator costs could have an impact on future study results.

90

NOx Allowances

• 1994 MOU established the Ozone Transport Commission

• 11 NE States and DC

• Cap on NOx emissions from major sources (May – September)

• Operated through 2003

91

NOx Allowances

• On May 1, 2003, compliance under the expanded NOx SIP Call market program began, to be implemented in phases

92

NOx Allowance Amounts

93

NOx Allowances Costs

• Driven by;– Continued ratcheting down of allowances to

meet ambient ozone standard.– High natural gas costs– Buying allowances as a stop-gap measure to

reduce capital expenditures– EPA estimates of $2000 to $2500 per ton for

average incremental control costs for the region.

94

NOx Allowance Costs

Dec. 31,2003 SIP NOx Prices

0100020003000400050006000700080009000

2003 2004 2005 2006 2007

Do

llars

pe

r T

on

Forward Prices (12/31/03) Spot Price (12/31/03)

95

NOx Allowances

• Consider that a coal-fired generator, with a 10,500 BTU/KWh heat rate and a 0.45 lbs.-NOx/MMBtu emission rate will incur an added production cost of more than $10.00 per MWh to account for the NOx allowances consumed at a $5,000 price.

• The impact of NOx allowance costs becomes even more important during a period of high gas costs.

96

SO2 Allowances

• Historically SO2 Allowances are lower than NOx Allowances– $200 vs. $ 2500 per ton– Less volatile than NOx Allowances

• Driven by much lower compliance costs

97

SO2 Allowance Cost

98

RTEP04 Assumption

• Include Allowance costs as an additional production cost

• Updated emission database to capture expected regulatory changes

• SO2 Allowances at $ 200 / ton• NOx Allowances (per ton)

• 2004 - $5000• 2005 - $5000• 2006 - $3500• 2007 - $2700• Beyond 2007 – $ 2200 EPA estimated

mitigation cost

99

Control Area Imports/Exports• Reviewed historic control area transfers

– Seasonal variations– On Peak vs. Off peak– Trends– Developments

100

Weekly Interchange Profile by Season

Historical Interchange Weekly Profile(Jan. 2002- Nov. 2003)(Negative Flow means Imports to NEPOOL)_Winter

-1400

-400

600

1 25 49 73 97 121 145

Hours

Inte

rch

ang

e F

low

(M

W)

AvgOfNEW YORK AvgOfNEW BRUNS

AvgOfPHASE I/II AvgOfHIGHGATE

Historical Interchange Weekly Profile(Jan. 2002- Nov. 2003)(Negative Flow means Imports to NEPOOL)_Summer

-1500

-1000

-500

0

500

1 25 49 73 97 121 145

Hours

Inte

rch

ang

e F

low

(M

W)

AvgOfNEW YORK AvgOfNEW BRUNS AvgOfPHASE I/II AvgOfHIGHGATE

101

Historical Interchange at Time of Daily Peak

H isto rica l In te rch an g e an d N E P OOL D aily P eak L o ad _2002

-1 50 0

-1 00 0

-50 0

0

50 0

1 00 0

1 50 0

2 00 0

1 31 6 1 91 12 1 1 5 1 1 81 21 1 2 4 1 2 71 30 1 3 31 3 61

D ay

Inte

rch

an

ge

(MW

)

0

5 00 0

1 00 00

1 50 00

2 00 00

2 50 00

3 00 00

NE

PO

OL

Da

ily

Pe

ak

Lo

ad

(M

W)

Ne wYo rk New Brun swick HQ Pha se II/I HQ Hig hg a te NE_ L O AD

Historical Interchange and NEPOOL Daily Peak Load_2003

-2000

-1000

0

1000

2000

1 31 61 91 121 151 181 211 241 271 301 331 361

Da y

Inte

rch

an

ge

(MW

)

050001000015000200002500030000

NE

PO

OL

Da

ily

Pe

ak

Lo

ad

(MW

)

NewYork New Brunswick HQ Phase II/I HQ Highgate NE_LOAD

102

Correlation between NE Daily Peak Load and Historical Interchange

Correlation between NEPOOL Daily Peak Load and Interchange_2002

-1500

-1000

-500

0

500

1000

1500

2000

11000 13000 15000 17000 19000 21000 23000 25000

Sorted NEPOOL Daily Peak Load

Inte

rch

an

ge

(M

W)

NewYork

New Brunswick

HQ Phase II/I

HQ Highgate

Corre lation be twee n NEPOO L Daily Peak Load and Interchange _2003

-2000

-1500

-1000

-500

0

500

1000

1500

2000

11000 13000 15000 17000 19000 21000 23000 25000

Sorte d NEP OOL Da ily P e a k Loa d

Inte

rch

an

ge

(M

W)

NewYork

New B runswick

HQ Phase II/I

HQ Highgate

103

RTEP04 Modeling Assumptions

• Seeking TEAC Input– NY

• 85 MW Import - NYPA Contract– NB

• 200 MW Fixed Import • 500 MW Import modeled as a gas fired combined cycle

unit– HQ

• 300 MW fixed Import• 500 MW Import modeled as a gas fired combined cycle

unit• 500 MW Import modeled as a gas fired steam unit• 200 MW Import modeled as a distillate GT

104

RTEP04 Resource Adequacy Analysis

TEAC20 PresentationMarch 4, 2004

Peter Wong ISO-NEPower Supply & Reliability

105

2004 Resource Adequacy Analysis

• Westinghouse/ABB Capacity Model Program used to determine single area NEPOOL LOLE covering 2004 through 2013

• Why run Westinghouse single area model”?– Determine NEPOOL Objective Capability/Installed Capacity

Requirements according to the current OC methodology– Provide signals to the market regarding future OC/ICAP

needs

Note: Weather related load forecast uncertainty is modeled.

106

2004 Resource Adequacy Analysis

• GE MARS used to determine sub-area LOLE covering the same time frame

• Why run the GE MARS model?– Determine the impact of transmission

constraints on NEPOOL generation resource adequacy. However, it does not capture transmission adequacy issues

– Provide signals to the market regarding future LICAP needs

Note: Weather related load forecast uncertainty is modeled.

107

Resource Adequacy Analysis Assumptions

• Loads – Based on 2004 CELT Data– Includes weather related load uncertainty

• Capacity Data– “CELT like” data – Difference in monthly SCC report reference

for winter rating– Capacity Additions – Based on 18.4 approval and under

construction (CELT includes all approved 18.4 Applications)– Capacity Attrition – Based on 18.4 approved retirements (CELT

does not include all approved 18.4 retirements/deactivations)– SWCT RFP– Known ICAP Contracts

• Any required expansion units needed to meet the NEPOOL criterion of 0.1 days/year LOLE have summer and winter ratings of 172.5 MW, 5 weeks of maintenance, and an equivalent forced outage rate (EFOR) of 10%

108

Resource Adequacy Analysis Assumptions

• Generating Unit Availability – 5 year historical performance (1999 – 2003)– New CC units break-in period represented

• Tie Reliability Benefits– 600 MW from NY year round– 200 MW from NB year round

• HQICC (when assumed)– As filed with FERC on December 31, 2003

• OP-4 Load Relief (327 MW* + 1.42% of load)– *Reflects 58 MW of Price Response Program Resources

• Load Response Program Assets– Values as of October 31, 2003

• Load Shift in CT and NEMA/BOSTON will be modeled

109

Capacity Addition Assumptions

Summer Rating (MW)

Milford Units 1 + 2 (SWCT) 490 Millstone 2 Uprate (CT) 31

Total 521

SWCT RFP (NOR & SWCT) 200

All assumed in service by June 1, 2004

110

Generating Unit Retirements

Summer Rating (MW)

Mason 4 – 6 98

Total 98

Assumed to be retired by June 1, 2004

111

Generating Unit Retirements

• To-be-Retired Units currently under RMR– Devon 7 and 8– New Boston– Salem Harbor 1 – 4 (RMR under negotiation)

• Units applied for 18.4 Deactivation (but denied)– Wallingford 2-5

112

Transmission Interface Transfer Limit

Assumptions (Static Limits Used for Modeling)

InterfacesInterface Limit Assumptions

(MW)

Basic Information for Interface Limits

ExplanationRelevant Study or

Descriptive Information

Availability

NB-NE700

2007 : 1000Stability NB-NE Tie Study

Public – Contact ISO-NE

HQ-NE (Highgate)

210HVDC Design

Limit and Voltage

N/A N/A

NY – NE (w/o Cross Sound

Cable)

Summer – 1,225

Winter – 1,475Thermal

NYISO S 2002 Operating Study NYISO 2001-02 Operating Study

Public – NYISO website

Cross Sound Cable

300 (NY to NE)

330 (NE to NY)

HVDC Equipment

Design LimitN/A N/A

HQ-NE (Phase II)

1500External Voltage

Constraints (PJM & NY)

Historical operating limit

N/A

113



InterfacesInterface Limit Assumptions

(MW)


ExplanationRelevant Study or

Descriptive Information

Availability

Maine – New Hampshire

1,400 Stability

2000 Maine Operating Study

NB – NE Tie Study

Confidential – Strategic

Information

Orrington South Export

2004: 1,050

2007: 1,200

Thermal (Summer) Bucksport System

Impact Study

Public – Contact Central

Maine Power

Surowiec South

1,150 Stability2000 Maine

Operating Study


Information

North - South

2,700Thermal

(Summer)Typical Operating

Study Results


Information

114



Interfaces

Interface Limit

Assumptions (MW)


ExplanationRelevant Study or Descriptive

InformationAvailability

Boston Import2004 : 3,600

2006 : 4,500 Thermal

(Summer)

Boston Import 2004 – 2008

Reliability Review

Public – ISO-NE website –

RC documents Section

SE Mass Export No limit Stability ISO-NE StudiesTo be

determined

(A)SE Mass/RI Export

(B)East – West

(C)Connecticut Import

(A)3,000

(B)2,400

(C)2,200

Simultaneous Stability / Thermal Voltage

ISO-NE StudiesTo be

determined

115



Interfaces

Interface Limit

Assumptions (MW)


ExplanationRelevant Study or Descriptive

InformationAvailability

Connecticut Export

2,030Thermal

(Summer)

Export Limit – NU Haddam Neck

SIS


Information

Southwest Connecticut

Import

2004: 2,000

2006: 2,550

2008: 3,400

Voltage

Thermal

Thermal

ISO-NE Studies

ISO-NE Studies

ISO-NE Studies

To be determined

To be determined

To be determined

Norwalk – Stamford

2004: 1,100

2006: 1,300

2008: 1,650

Thermal (Summer)

Typical Operating Study Result

ISO-NE Studies


Information

116

RTEP04 Resource Adequacy Cases

Case ID Single Area Simulation (SAS) Case Description

Case SAS1SAS using assumptions presented in TEAC19&20 at Reference Load Growth.

Case SAS2SAS using assumptions presented in TEAC19&20 at High Economic Load Growth.

Case SAS3SAS using assumptions presented in TEAC19&20 at Reference Load Growth and HQ Phase II assumed zero starting in 2005/06.

Case SAS4SAS using assumptions presented in TEAC19&20 at High Economic Load Growth and HQ Phase II assumed zero starting in 2005/06.

Case SAS5 - ???

Additional cases under development to cover possible unit retirements or additions

117

SAS Reference Load Growth (SAS1)

ICAP Resources included all New England claimed capacity (including units classified as Settlement Only), ICAP capable Load Response Resources, and Hydro Quebec Interconnection Credits

0.04330.043332,44133,71028,8802013-14

0.03000.030032,05933,71028,5502012-13

0.01910.019131,60833,71028,1702011-12

0.01090.010931,10433,71027,7402010-11

0.00670.006730,70233,71027,3902009-10

0.00420.004233,71027,0582008-09

0.00270.002733,71026,8152007-08

0.00170.001729,72133,71026,5702006-07

0.00100.001029,36633,71026,3052005-06

0.00050.000528,91533,71025,7352004-05

LOLE w/o Expansion

UnitsLOLE

Summer Requirement

(MW)

ICAP Resources

Summer (MW)

Peak Load(MW)

Power Year

0.04330.043332,44133,71028,8802013-14

0.03000.030032,05933,71028,5502012-13

0.01910.019131,60833,71028,1702011-12

0.01090.010931,10433,71027,7402010-11

0.00670.006730,70233,71027,3902009-10

0.00420.004233,71027,0582008-09

0.00270.002733,71026,8152007-08

0.00170.001729,72133,71026,5702006-07

0.00100.001029,36633,71026,3052005-06

0.00050.000528,91533,71025,7352004-05

LOLE w/o Expansion

UnitsLOLE

Summer Requirement

(MW)

ICAP Resources

Summer (MW)

Peak Load(MW)

Power Year

118

SAS Reference Load Growth (SAS1)

Total ICAP requirement reflect the accounting of the HQICC

2013-14

2012-13

2011-12

2010-11

2009-10

2008-09

2007-08

2006-07

2005-06

2004-05

Power Year

3,561

3,509

3,438

3,364

3,312

3,289

3,217

3,151

3,061

3,180

MW

Required Reserves

12.316.74,830

12.318.15,160

12.219.75,540

12.121.55,970

12.123.16,320

12.224.66,652

12.025.76,895

11.926.97,140

11.628.27,405

12.431.07,975

%%MW

Installed Reserves

2013-14

2012-13

2011-12

2010-11

2009-10

2008-09

2007-08

2006-07

2005-06

2004-05

Power Year

3,561

3,509

3,438

3,364

3,312

3,289

3,217

3,151

3,061

3,180

MW

Required Reserves

12.316.74,830

12.318.15,160

12.219.75,540

12.121.55,970

12.123.16,320

12.224.66,652

12.025.76,895

11.926.97,140

11.628.27,405

12.431.07,975

%%MW

Installed Reserves

119

SAS High Economic Load Growth (SAS2)

* 2 Proxy units added** 4 Proxy units added (total of 6 proxy units added)

ICAP Resources included all New England claimed capacity (including units classified as Settlement Only), ICAP capable Load Response Resources, and Hydro Quebec Interconnection Credits

LOLE w/o Expansion

UnitsLOLE

Summer Requirement

(MW)

ICAP ResourcesSummer

(MW)

Peak Load(MW)

Power Year

0.15170.091734,37134,745**30,4802013-14

0.12420.096033,73934,055*29,9652012-13

0.07260.072633,04933,71029,3902011-12

0.03800.038032,30333,71028,7652010-11

0.02010.020131,66233,71028,2152009-10

0.01070.010731,09533,71027,7302008-09

0.00560.005630,56933,71027,2802007-08

0.00270.002730,03633,71026,8452006-07

0.00120.001229,48833,71026,4152005-06

0.00050.000528,97833,71025,7902004-05

LOLE w/o Expansion

UnitsLOLE

Summer Requirement

(MW)

ICAP ResourcesSummer

(MW)

Peak Load(MW)

Power Year

0.15170.091734,37134,745**30,4802013-14

0.12420.096033,73934,055*29,9652012-13

0.07260.072633,04933,71029,3902011-12

0.03800.038032,30333,71028,7652010-11

0.02010.020131,66233,71028,2152009-10

0.01070.010731,09533,71027,7302008-09

0.00560.005630,56933,71027,2802007-08

0.00270.002730,03633,71026,8452006-07

0.00120.001229,48833,71026,4152005-06

0.00050.000528,97833,71025,7902004-05

120

SAS High Economic Load Growth (SAS2)

* 2 Proxy units added** 4 Proxy units added (total of 6 proxy units added)Total ICAP Requirement calculation reflect the accounting of the HQICC

2013-14

2012-13

2011-12

2010-11

2009-10

2008-09

2007-08

2006-07

2005-06

2004-05

Power Year

3,891

3,774

3,659

3,538

3,447

3,365

3,289

3,191

3,073

3,188

MW

Required Reserves

12.814.04,265**

12.613.64,090*

12.414.74,320

12.317.24,945

12.219.55,495

12.121.65,980

12.123.66,430

11.925.66,865

11.627.67,295

12.430.77,920

%%MW

Installed Reserves

2013-14

2012-13

2011-12

2010-11

2009-10

2008-09

2007-08

2006-07

2005-06

2004-05

Power Year

3,891

3,774

3,659

3,538

3,447

3,365

3,289

3,191

3,073

3,188

MW

Required Reserves

12.814.04,265**

12.613.64,090*

12.414.74,320

12.317.24,945

12.219.55,495

12.121.65,980

12.123.66,430

11.925.66,865

11.627.67,295

12.430.77,920

%%MW

Installed Reserves

121

SAS -Reference Load Growth (SAS3)

• 2 Proxy units added in 2013-14• HQICC included in ICAP Resources Total in 04/05 and assumed to be zero starting in

2005/06

0.12160.093032,49632,855*28,8802013-14

0.08890.088932,10032,51028,5502012-13

0.06050.060531,62332,51028,1702011-12

0.03780.037831,09832,51027,7402010-11

0.02500.025030,67532,51027,3902009-10

0.01700.017030,29832,51027,0582008-09

0.01180.011829,97432,51026,8152007-08

0.00800.008029,64732,51026,5702006-07

0.00490.004929,27032,51026,3052005-06

0.00050.000528,91533,71025,7352004-05

LOLE w/o Expansion

UnitsLOLE

Summer Requirement

(MW)

ICAP Resources

Summer (MW)

Peak Load(MW)

Power Year

0.12160.093032,49632,855*28,8802013-14

0.08890.088932,10032,51028,5502012-13

0.06050.060531,62332,51028,1702011-12

0.03780.037831,09832,51027,7402010-11

0.02500.025030,67532,51027,3902009-10

0.01700.017030,29832,51027,0582008-09

0.01180.011829,97432,51026,8152007-08

0.00800.008029,64732,51026,5702006-07

0.00490.004929,27032,51026,3052005-06

0.00050.000528,91533,71025,7352004-05

LOLE w/o Expansion

UnitsLOLE

Summer Requirement

(MW)

ICAP Resources

Summer (MW)

Peak Load(MW)

Power Year

122

SAS- Reference Load Growth (SAS3)

•2 Proxy units added in 2013-14•HQICC not included in Installed Capacity Total in 04/05 and assumed zero starting in 2005/06

2013-14

2012-13

2011-12

2010-11

2009-10

2008-09

2007-08

2006-07

2005-06

2004-05

Power Year

3,616

3,550

3,453

3,358

3,285

3,240

3,159

3,077

2,965

3,180

MW

Required Reserves

12.513.83,975

12.413.93,960

12.315.44,340

12.117.24,770

12.018.75,120

12.020.15,452

11.821.25,695

11.622.45,940

11.323.66,205

12.426.36,775

%%MW

Installed Reserves

2013-14

2012-13

2011-12

2010-11

2009-10

2008-09

2007-08

2006-07

2005-06

2004-05

Power Year

3,616

3,550

3,453

3,358

3,285

3,240

3,159

3,077

2,965

3,180

MW

Required Reserves

12.513.83,975

12.413.93,960

12.315.44,340

12.117.24,770

12.018.75,120

12.020.15,452

11.821.25,695

11.622.45,940

11.323.66,205

12.426.36,775

%%MW

Installed Reserves

123

SAS - High Economic Load Growth (SAS4)

• 1 Proxy unit added in 2010-11• 5 Proxy units added in 2011-12• 4 Proxy units added in 2012-13• 3 Proxy units added (total of 13 proxy units added) in 2013-14• HQICC included in ICAP Total in 04/05 but assumed to be zero starting in 2005-06

0.36500.096634,44534,753****30,4802013-14

0.30730.088833,81434,234***29,9652012-13

0.19100.087933,11433,545**29,3902011-12

0.10870.095132,35732,683*28,7652010-11

0.06330.063331,68532,51028,2152009-10

0.03730.037331,08832,51027,7302008-09

0.02170.021730,53632,51027,2802007-08

0.01180.011829,97732,51026,8452006-07

0.00580.005829,39532,51026,4152005-06

0.00050.000528,97833,71025,7902004-05

LOLE w/o Expansion

UnitsLOLE

Summer Requirement

(MW)

ICAP Resources

Summer MW

Peak Load(MW)

Power Year

0.36500.096634,44534,753****30,4802013-14

0.30730.088833,81434,234***29,9652012-13

0.19100.087933,11433,545**29,3902011-12

0.10870.095132,35732,683*28,7652010-11

0.06330.063331,68532,51028,2152009-10

0.03730.037331,08832,51027,7302008-09

0.02170.021730,53632,51027,2802007-08

0.01180.011829,97732,51026,8452006-07

0.00580.005829,39532,51026,4152005-06

0.00050.000528,97833,71025,7902004-05

LOLE w/o Expansion

UnitsLOLE

Summer Requirement

(MW)

ICAP Resources

Summer MW

Peak Load(MW)

Power Year

124

SAS- High Economic Load Growth (SAS4)

* 1 Proxy unit added** 5 Proxy units added*** 4 Proxy units added**** 3 Proxy units added (total of 13 proxy units added)HQICC included in ICap Total in 04/05 but assumed to be zero starting in 2005-06

2 0 1 3 -1 4

2 0 1 2 -1 3

2 0 1 1 -1 2

2 0 1 0 -1 1

2 0 0 9 -1 0

2 0 0 8 -0 9

2 0 0 7 -0 8

2 0 0 6 -0 7

2 0 0 5 -0 6

2 0 0 4 -0 5

P o w e r Y e a r

3 ,9 6 5

3 ,8 4 9

3 ,7 2 4

3 ,5 9 2

3 ,4 7 0

3 ,3 5 8

3 ,2 5 6

3 ,1 3 2

2 ,9 8 0

3 ,1 8 8

M W

R e q u ire d R e s e rv e s

1 3 .01 4 .04 ,2 7 3 * * * *

1 2 .81 4 .24 ,2 6 9 * * *

1 2 .71 4 .14 ,1 5 5 * *

1 2 .51 3 .63 ,9 1 8 *

1 2 .31 5 .24 ,2 9 5

1 2 .11 7 .24 ,7 8 0

1 1 .91 9 .25 ,2 3 0

1 1 .72 1 .15 ,6 6 5

1 1 .32 3 .16 ,0 9 5

1 2 .42 6 .16 ,7 2 0

%%M W

In s ta lle d R e s e r v e s

2 0 1 3 -1 4

2 0 1 2 -1 3

2 0 1 1 -1 2

2 0 1 0 -1 1

2 0 0 9 -1 0

2 0 0 8 -0 9

2 0 0 7 -0 8

2 0 0 6 -0 7

2 0 0 5 -0 6

2 0 0 4 -0 5

P o w e r Y e a r

3 ,9 6 5

3 ,8 4 9

3 ,7 2 4

3 ,5 9 2

3 ,4 7 0

3 ,3 5 8

3 ,2 5 6

3 ,1 3 2

2 ,9 8 0

3 ,1 8 8

M W

R e q u ire d R e s e rv e s

1 3 .01 4 .04 ,2 7 3 * * * *

1 2 .81 4 .24 ,2 6 9 * * *

1 2 .71 4 .14 ,1 5 5 * *

1 2 .51 3 .63 ,9 1 8 *

1 2 .31 5 .24 ,2 9 5

1 2 .11 7 .24 ,7 8 0

1 1 .91 9 .25 ,2 3 0

1 1 .72 1 .15 ,6 6 5

1 1 .32 3 .16 ,0 9 5

1 2 .42 6 .16 ,7 2 0

%%M W

In s ta lle d R e s e r v e s

125

Resource Adequacy MARS Cases

The following are some of the MARS multi-area cases for RTEP04. We seek your input for additional cases or modification of these proposed cases, including possible assumptions associated with these cases.

126


Case ID MARS Multi-Area Simulation Description

Case 1Existing transmission capabilities using assumptions presented in TEAC19&20.

Case 2 Case 1 w/o SWCT RFP 200 MW of resources

Case 3

Case 1 plus likely new generation & deactivations based on 18.4 approvals, retirement requests and future environmental regulations. Seeking TEAC Input

Case 4The SWCT Phase I & II as per current expected schedule.

127



Case 5 Additional resources estimated by examining the New England State Renewable Portfolio Standards

Case 6

Load reductions and additional resources forecast by the DR Market Penetration Study. Examine impacts assuming 100 % of potential is achieved over time.

128



Case 7 Improvements of the Boston import 345 kV cable project.

Case 7A Case 7 plus assumed likely retirements in the Boston Import Area

Case 7B

Boston Import Alternative – Additional quick start resources in the Boston Import area that will result in reliability similar to Case 7

129



Case 8 Impacts on CT Import (SEMA/RI export) Improvement Project.

Case 8A Case 8 with assumed CT area retirements

Case 8B

CT Import Alternative – Additional quick start resources in the CT Import area that will result in reliability similar to Case 8.

130



Case 9 Impacts of 2nd NB Tie.

Case 10 Impacts of CSC Export

Case11 Impacts of CSC Import

Cases 12a-x

Cases with fuel restrictions as provided by the FDWG.

131

GE MARS – NE System LOLE

Year

(Jan – Dec)

Case 1

With 200 MW RFP

Case 2

w/o 200 MW RFP

Case 4

With 200 MW RFP* and SWCT Phase I

and II

2004 0.003 0.016 0.003

2005 0.004 0.020 0.004

2006 0.007 0.027 0.011

2007 0.011 0.035 0.014

2008 0.015 0.047 0.020

2009 0.020 0.061 0.024

2010 0.031 0.097 0.035

2011 0.050 0.137 0.059

2012 0.080 0.215 0.082

2013 0.099 0.290 0.110

*The 200 MW RFP is assumed retired when SWCT Phase I is in service.

132

GE MARS Results CT Sub-Area LOLE

Year

(Jan – Dec)

Case 1

With 200 MW RFP

Case 2

w/o 200 MW RFP

Case 4


and II

2004 0.001 0.001 0.001

2005 0.001 0.002 0.001

2006 0.002 0.003 0.003

2007 0.002 0.003 0.003

2008 0.004 0.006 0.006

2009 0.005 0.006 0.007

2010 0.005 0.006 0.007

2011 0.009 0.012 0.012

2012 0.011 0.014 0.016

2013 0.013 0.017 0.018*The 200 MW RFP is assumed retired when SWCT Phase I is in service.

133

GE MARS Results

SWCT Sub-Area LOLEYear

(Jan – Dec)

Case 1

With 200 MW RFP

Case 2

w/o 200 MW RFP

Case 4


and II

2004 0.002 0.009 0.002

2005 0.003 0.013 0.003

2006 0.004 0.017 0.008

2007 0.005 0.021 0.009

2008 0.009 0.027 0.014

2009 0.012 0.037 0.016

2010 0.018 0.062 0.023

2011 0.028 0.084 0.040

2012 0.045 0.129 0.054

2013 0.059 0.170 0.078* The 200 MW RFP is assumed retired when SWCT Phase I is in service.

134

GE MARS Results NOR Sub-Area LOLE

Year

(Jan – Dec)

Case 1

With 200 MW RFP

Case 2

w/o 200 MW RFP

Case 4


and II

2004 0.002 0.012 0.002

2005 0.002 0.016 0.002

2006 0.004 0.021 0.009

2007 0.005 0.026 0.009

2008 0.008 0.028 0.014

2009 0.011 0.047 0.017

2010 0.016 0.078 0.024

2011 0.027 0.112 0.041

2012 0.044 0.179 0.055

2013 0.065 0.259 0.079* The 200 MW RFP is assumed retired when SWCT Phase I is in service.

135

GE MARS Results

Boston Sub-Area LOLEYear

(Jan – Dec)

Case 1

With 200 MW RFP

Case 2

w/o 200 MW RFP

Case 4


and II

2004 0.001 0.001 0.001

2005 0.001 0.001 0.001

2006 0.002 0.002 0.002

2007 0.005 0.005 0.005

2008 0.006 0.006 0.006

2009 0.007 0.008 0.007

2010 0.011 0.011 0.011

2011 0.019 0.018 0.019

2012 0.029 0.029 0.028

2013 0.033 0.034 0.034*The 200 MW RFP is assumed retired when SWCT Phase I is in service.

TEAC20

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