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TEAC14. Thursday, January 23, 2003 Radisson Hotel Marlborough Marlborough, Massachusetts Version for posting on the ISO-NE website. Certain information as been redacted for security reasons. Other corrections/changes made are noted. SWCT Reports Available.

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TEAC14

Thursday, January 23, 2003

Radisson Hotel Marlborough

Marlborough, Massachusetts

Version for posting on the ISO-NE website. Certain information as been redacted for security reasons. Other corrections/changes made are noted.


Swct reports available
SWCT Reports Available

  • To obtain paper or electronic version of the following reports contact ISO-NE Customer Service at 413 540 4220

    • Southwestern Connecticut Electric Reliability Study - Volume 1 - Final Power - Flow, Voltage and Short circuit

    • Southwestern Connecticut Electric Reliability Study - A Comparative Analysis of 345 kV Plumtree-Norwalk Overhead versus 2 -115 kV Cables from Plumtree - Norwalk.


TEAC14 Agenda

  • Welcoming Remarks

  • RTEP03 Scope Overview

  • Planning Assumptions

  • Update on Transmission Studies

    • SEMA/RI Export

    • Boston /NEMA -

      • Downtown

      • North Shore

  • RTEP Projects


Rtep03 scope
RTEP03 Scope

  • Reliability and Economic Assessments

    • Updated planning assumptions

    • MARS analysis by RTEP sub-area

    • SCED bus by bus analysis at selected load levels

    • Expanded IREMM analysis to reflect SMD

      • Historical Losses

      • Unit Commitment

      • Uplift

    • Several Cases to be studied

    • Incremental MARS & IREMM Analysis -2004



Rtep03 scope1
RTEP03 Scope

  • Transmission Planning Studies

    • SEMA/RI Export Improvement

    • ME Export Improvement

    • NEMA/Boston Improvement

  • Support Approved RTEP02 Projects

    • SWCT 345 kV

    • NW Vermont


Rtep03 scope2
RTEP03 Scope

  • Fuel Diversity Study

  • Analysis of Air Emission Impacts

  • Distributed Resources

  • LRP

  • Interregional Coordination


RTEP 03

Congestion Cost Methodology

Presentation to the Transmission Expansion Advisory Committee

January 23, 2003

Wayne Coste

Principal, IREMM, Inc.


Where We Have Been - RTEP 01

  • RTEP01 identified key transmission constraints

  • Economic congestion was estimated

    • Economic congestion created higher prices for some sub-areas

    • Interface ratings were significant (static)

    • Focus was on LMP effect of price volatility during high loads

    • ISO-NE Congestion Management System

      • Assumed SMD in place at the start of 2002

  • - ARR / FTR revenue reallocation same as RTEP01/02

    • Various assumptions tested using sensitivity cases

    • Tested the impact on several alternative bidding strategies

    • Did not include transmission “uplift” (generally off-peak),losses,load forecast uncertainty or sub-area internal limits

    • Tested relaxation of transmission constraints


Where We Have Been - RTEP 02

  • Used basic RTEP01 economic framework

  • Modeling refinements

    • Assumption updates for

      • fuel

      • new units

      • transmission upgrades

      • interchange assumptions

    • Interchange: combination of fixed import and CC based value

    • Effect of full unit outages on congestion

    • Limited representation of operating reserve

    • Monthly hydro profile developed

  • RTEP02 quantified impact of relaxation of transmission constraints


RTEP03 Goals

  • Forecast on-peak congestion (same as RTEP02)

  • Quantify off-peak “uplift”

    • Renamed in SMD “Operating Reserve Charges and Credits”

    • Will remain due to need to securely dispatch the system

    • Market screens approved by FERC on Dec 20th

  • Develop a more secure unit commitment

    • Include N-2 considerations

      • Loss of largest unit

      • Loss of second transmission element

  • Incorporate Transmission Losses

    • Transmission losses under SMD may be relatively high

  • Roll up results to SMD Reliability Zones


Improve Secure Dispatch Representation

  • ISO-NE has always operated under a secure dispatch

  • SMD will continue this operating practice

  • RTEP03 should reflect this practice

    • RTEP02 respected N-1 transmission limits

    • Operations also considers N-2 transmission limits

    • Typically transmission outages are the most constraining

  • For second contingency transmission outages

    • Interface ratings are lower

    • Count a portion of quick-start resources

    • Include ramp-rate from on-line units

    • Include OP-4 actions

    • Include allowable amounts of load shedding


Unit Commitment Process

  • Three (or more) passes for unit commitment

    • First pass - all units can operate at any level when needed

      • Interfaces at N-2 limits.

      • Identify units that could be flagged “ON” for economics

      • Remaining “uneconomic” units flagged “OFF”

    • Second pass with flagged “OFF” units, price spikes occur

      • Interfaces at N-2 limits.

      • Identify units that are needed to avoid price spikes

      • Remaining “uneconomic” units flagged “OFF”

    • Third pass with units flagged “ON” typically at LOL

      • Interfaces at N-1 limits.

      • Committed min block bids in at zero


Unit Commitment Data

  • Relatively few units can be added in unit commitment process

  • We will examine the following for impacts:

    • Start-up cost

    • Minimum run hours

    • Low operating limit

    • Incremental heat rates

  • Use physical limits for LOL (typically 25%)


LMP

  • LMP’s have three components

    • Energy Clearing Price

    • Congestion

      • - in areas of bottled generation

      • + in load pockets

    • Losses

      • + close to load center

      • - in remote exporting areas


Proxy CT Bid Screens in Constrained in Areas

  • Allowable safe harbor bids into import constrained areas

    • Addressed in FERC Dec 20th order

    • FERC desires to allow limited scarcity pricing

    • Based on cost of hypothetical new Proxy CT

      • Reduction due to prevailing ICAP revenue offset

      • Net difference in fixed cost is allocated over 500 or 2000 hr

      • At 500 hours - adder can be in the range of 300%

      • At 2000 hours - adder can be in the 50 - 80 % range


Indicative LMPs by Load Zone - Energy Component

  • Energy component is

  • uniform in all zones

  • (HISTORICAL

  • DATA)


Indicative LMPs by Load Zone - Congestion Component

  • Congestion

  • component can be

  • significant when

  • transmission

  • contingency is

  • binding

  • (HISTORICAL DATA)


Indicative LMPs by Load Zone - Loss Component

  • Loss component is

  • very non-linear and

  • affect importing and

  • exporting regions

  • Differently

  • (HISTORICAL DATA)


Indicative LMPs by Load Zone - Loss Component

  • Maine has lowest loss

  • component while Vermont

  • has the highest.

  • (Sept 2002)


Including Losses in RTEP03

  • We will use historic loss data by unit

  • Implications of loss component

    • Need to develop loss changes due to transmission upgrades

    • Distant generation may be penalized

    • Prevailing prices may rise if marginal units are

      • Electrically distant and

      • High losses


Sced analysis
SCED Analysis

  • SCED - Security Constrained Economic Dispatch program developed by PTI

  • GOAL – To identify the specific transmission facilities that may constrain and cause congestion on the New England system


Sced basics
SCED Basics

  • Analysis focuses on optimal operation of the system (generator dispatch + phase shifters)

  • Transfers and dispatches are calculated as part of an optimization process

  • Uses network load flow model employing a dc linearized powerflow calculation

  • Provides estimates of costs incurred to securely operate around transmission constraints

  • Identifies reliability problems when secure system operation is infeasible

  • Identify HUB price divergence


Sced analysis assumptions
SCED Analysis Assumptions

  • Similar Analysis performed as part of RTEP01

  • 2004 Summer Peak to be analyzed at a number of varying load levels (50, 60, 70, 80, 90 and 100%)

  • Sensitivities will be studied with larger units out of service


Interregional system planning process implementation plan

InterregionalSystem Planning ProcessImplementation Plan


Goals
Goals

  • Reduce Both Physical and Process System Planning Seams

  • Issue Draft Coordinated NY/NE System Plan by 1st Qtr. 2004

  • Expand upon NPCC planning process

    • Include MAAC/PJM

  • Increase coordination under NY and NE agreements with IMO and New Brunswick


Existing physical and process system planning seams
Existing Physical and Process System Planning Seams

  • Tie Line Capabilities

  • Phase II HVdc vs. Central East and PJM Interfaces

  • Interconnection and Tariff Studies

    • Queues

    • Interconnection Standards

  • Cost Allocation

  • Single Coordinated Plan


Process issues
Process Issues

  • Timing of FERC Decisions

    • SMD Rule

      • Planning

      • Pricing

    • Interconnection Rule

      • Queuing

  • Cost Sharing across ISO Borders

  • TO/ITC Issues

    • Differences in NY License Plate vs. NE Network Tariffs

    • Obligation to Build

    • Accommodation of Potential ITC(-s)

    • Formalization of Planning Process

  • State Issues


Opportunities to address physical issues
Opportunities to Address Physical Issues

  • Identify and Address Physical Seams

  • Form Initial Plan based upon Existing Procedures

    • RTEP02 and RTEP03

    • NY Power Alert

    • Existing NY and NE Interconnection Procedures

    • NPCC Annual Reviews

    • NPCC CP-10 Studies

  • Initiate Joint Studies

    • NY-NE Transfer Analysis

    • Loss of HQ Phase II Project

    • UPNY-SENY Impact on NE

    • Identify Small Ticket Improvements

    • Develop Preliminary Designs for Further Analysis


Process to address physical seams
Process to Address Physical Seams

  • Establish NY-NE Liaison Committee

  • Define Plan

    • Transmission Plan

    • Initially utilize existing planning procedures as approved by FERC

  • Coordinate with Regulatory Agencies

    • NYS DPS

    • NECPUC

    • FERC

  • Engage MP Committees

    • NEPOOL Participants Committee

    • NY Operating Committee

    • TEAC

  • Utilize agreements with IMO and NB to increase regional planning scope

  • Coordinate with NPCC and MAAC/PJM


Scope of work
Scope of Work

  • Assessment

    • Study Assumptions

      • Load Forecast

      • Generation I/S and Availability

      • Transportation Limits

      • Transmission Projects

      • Load Response/Distributed Resources

    • Establish Common Databases

      • MARS

      • IREMM/MAPS Congestion Projections

      • Transmission Analysis

    • NPCC Studies

      • Annual Reviews

      • CP-10

      • CP-8

      • Other TFSS Activities

  • Transmission Plan

    • Summary of Transmission Planning Studies

    • Include Project Status

    • Ensure Full Coordination of System Impact Studies and Transmission Improvements


RTEP03

Assessments Overview &

Assumptions

Peter K. Wong


Rtep03
RTEP03

  • Reliability Analysis 2003 - 2012

  • Economic Impact Assessment 2003 - 2012


Reliability analysis
Reliability Analysis

  • Reliability analysis (Resource Adequacy Assessment) to identify NEPOOL system reliability based on meeting the 1 Day in 10 Years Loss of Load Expectation criterion (disconnection of firm customers).

  • GE Multi-Area Reliability Simulation (MARS) program will be used for this analysis.


Economic impact assessment
Economic Impact Assessment

  • Congestion cost assessment to identify possible congestion trend is based on meeting NEPOOL energy requirements.

  • Congestion cost assessment will be conducted using a market based energy production simulator (IREMM).


Economic impact assessment1
Economic Impact Assessment

  • Estimate congestion cost as result of transmission constraints identified in transmission studies.

  • Estimate congestion cost as result of different bidding strategies.

    • Congestion based on price differences between sub-areas (market areas)

  • Estimate LMP losses component

  • Estimate Uplift impacts


Load and existing resources
Load and Existing Resources

  • Load and existing generating resource capability assumptions will be based on the 2003 CELT Report forecast.

  • Interruptible/dispatchable load and demand response assumptions will be based on the latest ISO-NE Settlement data.


Unit addition assumptions
Unit Addition Assumptions

  • Generating unit additions are based on approved 18.4 Applications and reflect those that have started construction as of January 2003.


Unit addition assumptions1
Unit Addition Assumptions

Summer Rating (MW)

AES Granite Ridge (NH)678

Milford Units 1 + 2 (SWCT)490

Mystic Units 8 + 9 (BOSTON) 1,414

Fore River (SEMA) 700

English Station 7 + 8 (CT) 70

Great Northern Hydro (BHE)*126

Total 3,478

All assumed in service by June 1, 2003

*18.4 Application submittal expected in Feb/Mar 2003


Generation out of service
Generation Out of Service

  • Devon 7 and 8 are assumed deactivated when Milford units are in service.

  • New Boston 1 is assumed retired when Sithe Mystic 9 is in service. (corrections in red)

  • No other generation deactivations or retirements are assumed in the base case.


Generating unit energy
Generating Unit Energy

  • Generation from fossil fueled units will be calculated as a function of their short run marginal costs.

  • Generation from hydro units are modeled using a historical monthly generation profile.

  • Generation from pumped-storage units will reflect an assumed 10% capacity factor and 75% efficiency.


RTEP AssumptionsGeneration Other Adjustments

  • CELT Capacity Changes

  • Change in effective MW due to different forced outage rates


Generating unit availability
Generating Unit Availability

  • Generator unit availabilities are based on 5-year average of historical data (1998 - 2002).

  • Data Sources are as follows:

    • NABS for 1998 thru April 1999.

    • ISO Short Term Generator Outage Data Base for May 1999 thru April 2000.

    • ISO Unit Availability Database for May 2000 thru December 2002.


Generating unit availability1
Generating Unit Availability

  • For new units, unit immaturity is assumed for first 3 years of operation. After this period, unit historical data and TUA is used to develop the 5 year average.

  • Forced outage assumptions for nuclear units with extended outage are based on NEPOOL Target Unit Availabilities except for the first year of the long outage.


Generating unit availability2
Generating Unit Availability

  • For the first year of the long nuclear outage, any outage longer than 6 months would be represented by 6 months of forced outage averaged with either historical data or TUA (TUA is used if the unit is on outage the remainder of the year).


Existing Generating Unit Availability(Percent) (edited to indicate gas turbine and jet statistics separately)


Interchange assumptions for base economic impact analysis
Interchange Assumptions for Base Economic Impact Analysis

Updated RTEP02 methodology with base plus price sensitive transactions

  • LI sound cables (Scenario Based)


Fuel price assumptions
Fuel Price Assumptions

  • Fuel Price Forecast Based on Energy Information Administration’s

  • Annual Energy Outlook (Dec 2002 AEO) for 2004+

  • Short term outlook for 2003, 2004

  • “Reference Case” forecast was used







Interface limits
Interface Limits

  • Update for

    • Impacts of Upgrade Timing

    • Results of Planning Studies


Draft 4 03 forecast of net energy for load and seasonal peaks

Draft 4/03 Forecast ofNet Energy for Load and Seasonal Peaks

David Ehrlich

ISO New England

Principal Analyst, Load Forecasting,System Planning


Summer Peaks for States & Selected Operating Companies

2003

2008

CAGR%

CONNECTICUT:

6900

7253

1.0

ISO: State peaks & Operating Company 2002 Weather Normal

CMEEC

328

343

0.9

UI

1367

1460

1.3

CLP

4682

4880

0.8

MAINE:

1970

2114

1.4

BHE

316

308

-0.5

CMP

1833

1804

-0.3

MASSACHUSETTS:

11510

12468

1.6

BECO

3233

3563

2.0

EED

691

729

1.1

FERC715: Operating Company 2003 & 2008 Forecasts

MECO

3980

4277

1.4

WMECO+HWP

773

803

0.7

NEW HAMPSHIRE:

2110

2326

2.0

UNITIL

260

306

3.3

GSE

182

202

2.1

PSNH

1472

1508

0.5

RHODE ISLAND:

1730

1851

1.4

BVE

343

354

0.7

NEC

125

137

1.9

NECO

1334

1418

1.2

VERMONT:

975

1020

1.9

VELCO

975

1102

2.5



Focus
FOCUS

  • NEMA / Boston

    • North Shore

    • Downtown

  • SEMA / RI Export

  • Update on remaining RTEP studies


Nema boston planning study

NEMA/Boston Planning Study

TEAC Update

January 23, 2003


Study objectives
Study Objectives

  • Assess local reliability and dependence on local generation

  • Identify short term projects that could be completed by 2006 or earlier

  • Identify long term projects as required


Areas of Concern

map redacted


Generation
Generation

  • North Shore

    • 1150 MW of load

    • Salem Harbor 1-4 743MW

  • Downtown Boston

    • 1000 MW of load

    • Mystic4-6 379MW

    • Mystic7 565MW

    • Mystic Block8 800MW

    • Mystic Block9 800MW

    • New Boston 380MW


Analyses performed
Analyses Performed

  • Thermal & Voltage Load Flow Analysis

  • Short Circuit


Initial conditions studied
Initial Conditions Studied

  • 25800 Load Level

  • Reduced Generation at Salem for North Shore Cases

  • Cases with and without 115kV Generation in Downtown Boston

  • Various system stresses and dispatches


Problems found
Problems Found

  • Reliability

    • North Shore Transmission Overloads

    • Downtown Boston Transmission Overloads


North Shore Current Conditions

  • Overloads occur for load levels experienced today

  • North Shore Import limit determined to be approximately 500 MW

  • All North Shore generation needed to assure transmission adequacy


Transmission facility overloads
Transmission Facility Overloads

  • North Shore (low generation cases)

    • REDACTED


Two alternatives investigated for the north shore
Two Alternatives Investigated for the North Shore

  • Package 1: Straightforward Replacement of Overloaded Facilities

  • Package 2: Addition of 345kV Ring Bus at Ward Hill, second Ward Hill 345/115kV Transformer, and replacement of the remaining overloaded facilities


Package comparison
Package Comparison

  • Package 1

    • Allows for 1100MW of imports

    • Eliminates the dependency on North Shore generation

    • Uses Non-Standard sized transformers which would have no system spare

    • More expensive


Package comparison1
Package Comparison

  • Package 2

    • Allows for 1000MW of imports

    • Would require 112 MW of generation at North Shore

    • Uses Standard Size Equipment

    • Better Voltage and Thermal Performance

    • Better platform for implementing long term solutions



Downtown boston conditions
Downtown Boston Conditions

  • Overloads occur for load levels experienced today

  • 1000 MW of load in downtown Boston


Transmission facility overloads1
Transmission Facility Overloads

  • All 115kV generation off

    • Numerous overloads in Downtown Area

  • 115kV generation on

    • redacted

    • Loading on several other 115kV facilities slightly over LTE


Recommended solutions downtown boston
Recommended Solutions (Downtown Boston)

  • Upgrade of circulation equipment of two Downtown Boston cables

    • redacted

  • Still requires generation on Downtown Boston 115kV system


Sema ri export capability enhancement
SEMA / RIEXPORT CAPABILITYENHANCEMENT


Objective
Objective

  • Assess the existing stability and thermal export limits, determine major (long term) and minor (short term) upgrades to enhance the export capability.

  • Address congestion and reliability issues associated with locked-in and locked-out generation

    • Address locked-in generation in SEMA/RI & Eastern New England

    • Address line loading, voltage, stability and torsional reclosing issues

    • Increase CT and NEMA/Boston import capabilities

    • Increase East to West transfer capability


Current status stability
Current Status - Stability

  • Report complete on existing stability limits (“2002/03 Southeast Massachusetts / Rhode Island Export and Short – Term Upgrade Analysis”)

  • Report is available from ISO-NE Customer Service


Current status thermal
Current Status - Thermal

  • Preliminary analysis to assess the thermal export capability for the system as planned is ongoing.

  • Ongoing analysis to assess the benefit of various 345kV projects.


Results stability performance analysis
Results – Stability Performance Analysis

  • Stability limits were based on the result of three-phase fault with delayed clearing extreme contingency which resulted in a transiently unstable response

  • All applicable contingencies were evaluated


Results stability performance analysis1
Results – Stability Performance Analysis

  • The existing simultaneous stability transfer limits were found to be:

    • E/W 850

    • SEMA/RI 2400

    • SEMA 400


Recommendation stability performance analysis
Recommendation – Stability Performance Analysis

  • Modify the following breakers for Independent Pole Tripping operation:

    • West Medway 111, 112 (completed)

    • Millbury 314 (Completed)

    • West Walpole 104, 105, 108, 109 (2003)

    • Sherman Road 142 (Complete)

  • IPT Modification results in improved stability limits:

    • E/W 2400

    • SEMA/RI 3000

    • SEMA 2300






  • Follow up stability analysis
    Follow-Up Stability Analysis

    • Upgrades to the Canal breakers or reducing the backup breaker clearing time would eliminate the possibility of an extreme contingency involving those breakers causing a total source loss over 2200 MW.

    • Upgrading Brayton Point circuit breaker 15-300T and 03-300T to IPT would eliminate the possibility of an extreme contingency involving those breakers causing a total source loss over 2200 MW.


    Results thermal performance analysis
    Results – Thermal Performance Analysis

    • The existing thermal transfer limits for the 2006 “As Planned” system were found to be 2200 - 3000 MW.

    • Range limit determined by varying (1) sources in SEMARI and sinks in NEPOOL and (2) levels of E/W transfer in the base case.

    • SEMA/RI Exports limit is highly dependent on:

      • East/West Transfers

      • CT Import

      • NEMA Import


    Results thermal
    Results - Thermal

    These projects studied to date can improve SEMA/RI East – West and CT Import Capabilities

    ProjectThermal Export Range

    • Option 1

      • Card-West Farnum-Sherman-Millbury 345kV 2700 – 4200

    • Option 2

      • Mntvlle-Kent-W Farnm-Shrmn-Milbry 345kV 2700 – 4200

    • Existing 2200 - 3000




    Follow up thermal
    Follow-Up Thermal

    • Currently evaluating the benefit of two separate options which improve SEMA/RI to NEMA Boston area Transfer Capabilities:

      • Option 1

        • Tapping the 316 Line between Holbrook and West Walpole at Canton, adding a 345kV line from Canton to Hyde Park, 115kV from Hyde Park to Dewar St with a 345/115kV transformer at Hyde Park.

      • Option 2

        • Adding 345kV line from Holbrook-Edgar-K St-Mystic with 345/115kv transformers at Edgar, K St, and Mystic.




    4 13 northwest vermont reliability study
    4.13 Northwest Vermont Reliability Study

    • TEAC 12 - 11/19/2002 – Rutland

    • Focus on Vermont Issues

    • Major reports, including 4.13, complete

    • ISO Board Approval

    • Vermont Regulatory Process continuing


    4 26 southwest connecticut area reliability assessment
    4.26 Southwest Connecticut Area Reliability Assessment

    • TEAC 13 - 12/5/2002 – New Britain

    • Focus on Connecticut Issues

    • Final Thermal, Voltage, Short Circuit Report discussed & made available

    • Comparison of Towns’ proposal to 345kV discussed & made available

    • Stability & 15.5 Review work continuing


    Maine new hampshire studies
    Maine/New Hampshire Studies

    • 4.2 Keswick GCX SPS alternatives assessment 2003

    • 4.3 Maine Independence Station L/O Section

      396 SPS Arming or Removal Study 2003

    • 4.4 MEPCO Corridor SPS Design Review 2003

    • 4.5 BHE Down East Transmission Reliability

      Improvement Assessment (Line 61) 2003

    • 4.6 CMP Autotransformer Reliability

      Assessment 2003


    Maine new hampshire studies1
    Maine/New Hampshire Studies

    • 4.7Maine-New Hampshire Voltage Performance Assessment

      • Minor/short-term upgrades (Stage 1) Complete

      • Major/long-term upgrades (Stage 2) 2003

    • 4.8Maine-New Hampshire & North South Transfer Capability Enhancement

      • Minor upgrades (Stage 1) Complete

      • Major upgrades (Stage 2) 2003


    Maine new hampshire studies2
    Maine/New Hampshire Studies

    • 4.9 Central New Hampshire & Western Maine

      Transfer Capability Enhancement

      (Y138 closing) 2003

    • 4.10 Southern New Hampshire Area Import

      Capability Enhancement Complete


    Vermont studies
    Vermont Studies

    • 4.11 Essex Capacitor Study Complete

    • 4.12 Vermont Long Range Study Complete

    • 4.13 Northwest Vermont Reliability Study Complete

    • 4.14 Vermont Northern Loop Study Complete

    • 4.15 Southwest Vermont / Southeast New

      Hampshire / Central Massachusetts

      Regional Study 2003


    Western central ma studies
    Western / Central MA Studies

    • 4.16 Greater Metro-West Transmission Supply

      Study Complete

    • 4.17 Central MA Reliability Study 2003

    • 4.18 Springfield/Western Massachusetts Area

      Reliability Assessment 2003

    • 4.30 Western MA Fault Duty Studies Complete


    Northeastern ma boston studies
    Northeastern MA/Boston Studies

    • 4.19 NEMA/Boston Import Capability

      Enhancement

      • Near-term Limitations (Part 1) Complete

      • Long-term Limitations (Part 2) 2003

    • NEW NEMA Area NPCC Bulk Power System

      Assessment 2003


    Northeastern ma boston studies1
    Northeastern MA/Boston Studies

    • 4.20 Norwood M.L.D. Station Addition Complete

    • 4.21 Auburn Area Study Complete

    • NEW North Shore / Merrimack Valley

      Reliability Study 2003


    Southeastern ma rhode island studies
    Southeastern MA/Rhode Island Studies

    • 4.23 Southeastern MA/RI Export Capability

      Assessment

      • Stability Limit Assessment & Short Term Upgrades Complete

      • Major/Long Term Upgrades2003

    • NEW Southeastern MA/RI Reliability Study 2003

    • 4.22 Cape Cod Supply Study 2003


    Connecticut studies
    Connecticut Studies

    • 4.24 Northwest Connecticut Area Import

      Capability Enhancement Complete

    • 4.25 Glenbrook STATCOM Complete

    • 4.26 Southwest Connecticut (SWCT) Area

      Reliability Assessment 2003

    • 4.27 1385 Cable Replacement Study Complete

    • NEW Middletown, Connecticut Area

      Reliability Assessment 2003

    • NEW Eastern Connecticut Area Reliability

      Assessment 2003

    • 4.29 CL&P Fault Duty Studies Complete


    New england regional
    New England Regional

    • 4.28 East-West Oscillation Analysis 2003

    • NEW Excitation System Tuning Study 2003



    Projects 20m
    Projects > $ 20M

    Cost 18.4 Projected

    ISD

    • 4.13 NW Vermont Reliability Project 156.3 Yes 2004-7

    • 4.26 SWCT 345 kV Phase I 150.0 No 2005

    • 4.26 SWCT 345 kV Phase II 450.0 No 2008

    • 4.27 Norwalk Harbor – Northport

      138 kV line 1385 replacement 40.0 Yes 2004

      Updates of cost and In Service Dates (ISD) based on representations of

      the Transmission Owners


    20m projects 1m
    $ 20M > Projects > $ 1M

    Costs 18.4 Projected

    ISD

    • 4.7 Maxcys & Western Maine

      Capacitors 6.0 No 2003

    • 4.7 Ocean Road & Three Rivers

      Capacitors 2.5 No 2003-4

    • 4.8 Quaker Hill to Three Rivers

      115 kV 197 line upgrade 3.0 No 2003

    • 4.8 Maguire to Three Rivers 115kV

      250 line upgrade TBA No 2003

    • 4.9 Projects A/W Y138 Line Closing 7.0 No 2005

    • 4.10 Deerfield to Garvins 115 kV

      G146 Line rebuild 8.5 Yes 2003

      Updates of cost and In Service Dates (ISD) based on representations of

      the Transmission Owners


    20m projects 1m1
    $ 20M > Projects > $ 1M

    Cost 18.4 Projected

    ISD

    • 4.10 Rebuild Scobie 115 kV substation 9.5 Yes 2005

    • 4.10 Second 345/115 kV Scobie

      autotransformer 7.0 Yes 2004

    • 4.14 Vermont Northern Loop Project 17.0 Yes 2004

    • 4.16 Reconductor W-23 Woodside-

      Northborough / Fitch Rd 69kV TBA Yes Complete

    • 4.16 Northborough 115 kV Capacitor 1.3 Yes Complete

    • 4.16 Millbury 115 kV Capacitor Bank 1.1 Yes Complete

    • 4.16 Second Wachusetts 115/69

      Autotransformer TBA No 2004

      Updates of cost and In Service Dates (ISD) based on

      representations of the Transmission Owners


    20m projects 1m2
    $ 20M > Projects > $ 1M

    Cost 18.4 Projected

    ISD

    • 4.16 Reconductor Fitch Rd to Pratts

      Junction 69kV Line N40 TBA No 2004

    • 4.20 Norwood Station Addition 11.4 Yes Complete

    • 4.21 Auburn Area Improvements TBA Yes 2002-6

    • 4.22 Cape Supply Improvements 9.0 No 2003

    • 4.23 Replace West Walpole 104,105,108,

      109 with IPT breakers 2.5 NR 2003

      Updates of cost and In Service Dates (ISD) based on

      representations of the Transmission Owners


    20m projects 1m3
    $ 20M > Projects > $ 1M

    Cost 18.4 Projected

    • ISD

  • 4.24 Reconductor Canton-North

    Bloomfield 115 kV line 1732

    and add shunt capacitors at

    Franklin Drive and Canton 12.7 Yes 2003

  • 4.25 Glenbrook Static VAR

    Compensator 16.0 Yes 2004

  • 4.29 Replace CL&P Overstressed

    Breakers 5.4 Yes 2003

  • 4.30 Replace Western MA

    Overstressed Breakers 1.5 Yes 2003

    Updates of cost and In Service Dates (ISD) based on

    representations of the Transmission Owners


  • Projects 1m
    Projects < $ 1M

    Cost 18.4 Projected

    ISD

    • 4.8 Schiller to Three Rivers 115 kV

      N133 line upgrade 0.3 NR 2003

    • 4.11 Essex Capacitors 0.7 Yes Complete

    • 4.16 Install Woodside breaker TBA No 2003

    • 4.16 Install tie breaker & 2nd radial

      Northborough–Hudson 115 kV 0.5 Yes 2003

    • 4.23 Re-wire West Medway 111, 112

      to IPT 0.0 NR Complete

    • 4.23 Modify Millbury 314 &

      Sherman Road 142 to IPT 0.2 NR Complete

      Updates of cost and In Service Dates (ISD) based on

      representations of the Transmission Owners


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