TEAC14

1
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.

2
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.

3
TEAC14 Agenda

• Welcoming Remarks
• RTEP03 Scope Overview
• Planning Assumptions
• Update on Transmission Studies
• SEMA/RI Export
• Boston /NEMA -
• Downtown
• North Shore
• RTEP Projects

4
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

5
RTEP03 Cases

6
Case ID Case Description IREMM MARS SCED
1 Base, Sub-Area Transfer limits with RTEP02 Appendix 13.5.C Interface Transmission Elements (updated to include Upgrades anticipated by 04.01.03 )and RTEP03 load, generation, fuel cost, and other Control Area assumptions Fuel Based Bids Y 50,60, 70,80, 90 100 Percent Load Levels 2004
1A Case 1 Higher Bids NA TBD
1B Case 1 Fuel Oil Cost 25 NA TBD
1C Case 1 Gas Costs 25 NA TBD
1D Generator Attrition Case Y Y Y
1E HQ Ph II at 2000 MW Y Y TBD
7

Case ID Case Description IREMM MARS SCED
2 Glenbrook Statcom Y Y TBD
3 SWCT 345 kV Ph I Y Y TBD
4 SWCT 345 kV Ph II Y Y TBD
5 SEMA/RI Export Improvement Y Y TBD
6 ME Export Improvement Y Y TBD
7 NEMA/Boston Import Improvement Y Y TBD
8 NW VT Improvement Y Y TBD
9 Improvements Cases 2-8 Y Y TBD
9A Case 9 w/ higher bidding Y N TBD
8
RTEP03 Scope

• Transmission Planning Studies
• SEMA/RI Export Improvement
• ME Export Improvement
• NEMA/Boston Improvement
• Support Approved RTEP02 Projects
• SWCT 345 kV
• NW Vermont

9
RTEP03 Scope

• Fuel Diversity Study
• Analysis of Air Emission Impacts
• Distributed Resources
• LRP
• Interregional Coordination

10
RTEP 03 Congestion Cost Methodology
Presentation to the Transmission Expansion
Advisory Committee January 23, 2003 Wayne
Coste Principal, IREMM, Inc.
11
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

12
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

13
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

14
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

15
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

16
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)

17
LMP

• LMPs have three components
• Energy Clearing Price
• Congestion
• - in areas of bottled generation
• in load pockets
• Losses
• close to load center
• - in remote exporting areas

18
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

19
Indicative LMPs by Load Zone - Energy Component

• Energy component is
• uniform in all zones
• (HISTORICAL
• DATA)

20
Indicative LMPs by Load Zone - Congestion
Component

• Congestion
• component can be
• significant when
• transmission
• contingency is
• binding
• (HISTORICAL DATA)

21
Indicative LMPs by Load Zone - Loss Component

• Loss component is
• very non-linear and
• affect importing and
• exporting regions
• Differently
• (HISTORICAL DATA)

22
Indicative LMPs by Load Zone - Loss Component

• Maine has lowest loss
• component while Vermont
• has the highest.
• (Sept 2002)

23
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

24
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

25
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

26
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

27
InterregionalSystem Planning ProcessImplementat
ion Plan
28
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

29
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

30
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

31
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

32
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

33
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

34
RTEP03 Assessments Overview Assumptions Peter
K. Wong
35
RTEP03

• Reliability Analysis 2003 - 2012
• Economic Impact Assessment 2003 - 2012

36
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.

37
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).

38
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

39
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.

40
Unit Addition Assumptions

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

41
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

42
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.

43
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.

44
RTEP AssumptionsGeneration Other Adjustments

• CELT Capacity Changes
• Change in effective MW due to different forced
  outage rates

45
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.

46
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.

47
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).

48
Existing Generating Unit Availability(Perce
nt) (edited to indicate gas turbine and jet
statistics separately)
49
Interchange Assumptions for Base Economic
Impact Analysis

• Updated RTEP02 methodology with base plus price
  sensitive transactions
• LI sound cables (Scenario Based)

50
Fuel Price Assumptions

• Fuel Price Forecast Based on Energy Information
  Administrations
• Annual Energy Outlook (Dec 2002 AEO) for 2004
• Short term outlook for 2003, 2004
• Reference Case forecast was used

51
RTEP Assumptions - Fuel Costs
52
RTEP Assumptions - Fuel Costs
53
RTEP Assumptions - Fuel Costs
54
RTEP Assumptions - Fuel Costs
55
RTEP Assumptions - Fuel Costs
56
Interface Limits

• Update for
• Impacts of Upgrade Timing
• Results of Planning Studies

57
Draft 4/03 Forecast ofNet Energy for Load and
Seasonal Peaks

• David Ehrlich
• ISO New England
• Principal Analyst, Load Forecasting,System
  Planning

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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
WMECOHWP
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
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STATUS OF RTEP STUDIES

80
FOCUS

• NEMA / Boston
• North Shore
• Downtown
• SEMA / RI Export
• Update on remaining RTEP studies

81
NEMA/Boston Planning Study

• TEAC Update
• January 23, 2003

82
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

83
Areas of Concern map redacted
84
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

85
Analyses Performed

• Thermal Voltage Load Flow Analysis
• Short Circuit

86
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

87
Problems Found

• Reliability
• North Shore Transmission Overloads
• Downtown Boston Transmission Overloads

88
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

89
Transmission Facility Overloads

• North Shore (low generation cases)
• REDACTED

90
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

91
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

92
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

93
Ward Hill One Line Diagram for Package 2
redacted
94
Downtown Boston Conditions

• Overloads occur for load levels experienced today
• 1000 MW of load in downtown Boston

95
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

96
Recommended Solutions (Downtown Boston)

• Upgrade of circulation equipment of two Downtown
  Boston cables
• redacted
• Still requires generation on Downtown Boston
  115kV system

97
SEMA / RIEXPORT CAPABILITYENHANCEMENT
98
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

99
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

100
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.

101
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

102
Results Stability Performance Analysis

• The existing simultaneous stability transfer
  limits were found to be
• E/W 850
• SEMA/RI 2400
• SEMA 400

103
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

104
redacted
105
redacted
106
redacted
107
redacted
108
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.

109
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

110
Results - Thermal

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

111
SEMARI (CT Import) Option 1
redacted
112
SEMARI (CT Import) Option 2
redacted
113
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.

114
SEMARI ( NEMA Import) Option 1
redacted
115
SEMARI ( NEMA Import) Option 2
redacted
116
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

117
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

118
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

119
Maine/New Hampshire Studies

• 4.7 Maine-New Hampshire Voltage Performance
  Assessment
• Minor/short-term upgrades (Stage 1)
  Complete
• Major/long-term upgrades (Stage 2) 2003
• 4.8 Maine-New Hampshire North South Transfer
  Capability Enhancement
• Minor upgrades (Stage 1) Complete
• Major upgrades (Stage 2) 2003

120
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

121
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

122
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

123
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

124
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

125
Southeastern MA/Rhode Island Studies

• 4.23 Southeastern MA/RI Export Capability
• Assessment
• Stability Limit Assessment Short Term
  Upgrades Complete
• Major/Long Term Upgrades 2003
• NEW Southeastern MA/RI Reliability Study
  2003
• 4.22 Cape Cod Supply Study 2003

126
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 CLP Fault Duty Studies Complete

127
New England Regional

• 4.28 East-West Oscillation Analysis 2003
• NEW Excitation System Tuning Study 2003

128
STATUS OF RTEP PROJECTS

129
Projects gt 20M

• 
  Cost 18.4 Projected
• ISD
• 4.13 NW Vermont Reliability Project 156.3 Yes 200
  4-7
• 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

130
20M gt Projects gt 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

131
20M gt Projects gt 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

132
20M gt Projects gt 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

133
20M gt Projects gt 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 CLP 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

134
Projects lt 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
• NorthboroughHudson 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