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TEAC22. Wednesday, June 2, 2004 Radisson Hotel Marlborough, Massachusetts. TEAC22 Agenda. Welcoming Remarks Fuel Diversity Issues Power Plant Emissions Renewable Standards Impacts Operable Capacity Analysis New England Capacity Outlook

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Teac22

TEAC22

Wednesday, June 2, 2004

Radisson Hotel

Marlborough, Massachusetts


Teac22

TEAC22 Agenda

  • Welcoming Remarks

  • Fuel Diversity Issues

  • Power Plant Emissions

  • Renewable Standards Impacts

  • Operable Capacity Analysis

  • New England Capacity Outlook

  • Transmission Planning Studies Updates


Teac22

TEAC23 - June 25th

  • Historical Market Data

  • Economic Benchmarking

  • LICAP

  • Price Responsive Load Response Analysis


Teac22

Transmission Expansion

Advisory Committee

22nd Meeting

Cold Snap Activities Update

June 2, 2004

Marlborough, Ma

Mark Babula - ISO-NE


Teac22

Fuel Diversity Working Group (FDWG):

  • Five (5) meetings to date

  • January 2004 Cold Snap:

    • Charged with the Electric & Gas Wholesale Initiative (EGWI) Project

    • Working in concert with the NEPOOL Cold Snap Task Force (CSTF)

  • Revising Fuel Diversity Assessment within RTEP04 to address concerns


Teac22

Development of Issue List:

  • 51 original items – post January Cold Snap

  • Issues compiled from various sources

  • Closed-out 19 issues – 32 open items

  • Segmented into 3 categories:

    • Reliability, Markets & Communications

  • Action item assignees & target completion dates

  • Posted on FDWG & CSTF web-sites


Teac22

ISO Activities on Cold Snap Issues:

  • Three high priority, short-term objectives targeted for implementation prior to Winter 2004/2005

    • Formation of the Electric & Gas Operations Committee

    • Cold Snap Initiated - Electric Market Timeline Advancement

    • Materialization of more dual fuel capability


Teac22

ISO Activities on Reliability Issues:

  • Assessing modifications to Objective Capability

  • Revising the Fuel Diversity Assessment within TEAC’s - RTEP04

  • Investigating the identification of common mode failures on fuel supply & delivery systems

  • Assessing impacts of rolling blackouts & reviewing system restoration

  • Revisiting dual fuel issues


Teac22

Revisiting Dual Fuel Issues:

  • How much do we really have?

  • Is it in the right location?

  • What are its limitations on sustainability?

    -----------------------------------------------------------

  • How much do we really need & where?

  • How can we better manage that resource pool?

  • How can we make more dual fuel capability materialize?


Teac22

ISO Dual Fuel Activities:

  • Assess Current Dual Fuel Capability

    • Obtain generator air, water & oil storage permits

    • Summarize fuel switching provisions and limitations

  • Analyze Dual Fuel Constraints

    • Determine the regulatory, design and operating constraints on single fuel units that impede or preclude dual fuel capability


Teac22

ISO Dual Fuel Activities:

  • Assess Dual Fuel Expansion Strategies & Perform Feasibility Analysis

    • Identify technical, regulatory & policy alternatives that would serve to improve dual fuel opportunities

    • Assess ramifications and likelihood of alternatives, along with regional issues

    • Review alternatives with State Agencies to evaluate viability & concerns

  • Meetings scheduled with Air Regulators


Teac22

ISO Activities on Market Issues:

  • Gas & electric market timelines & scheduling

    • Straw proposal on market timeline advancement

  • Review of existing electric market rules for proper incentives & penalties

    • Does LICAP reflect proper incentives for delivery

    • Should gas-only generation be required to have and use firm transportation to supply NEPOOL load.

  • Equitable reimbursement of operating costs

  • Minimization and management of risk


Teac22

ISO Activities on Communications Issues:

  • Reviewing and revising Operating Procedure #5 – Generator Outage & Maintenance Scheduling (i.e. economic outages)

  • Enhancing communications associated with Operating Procedure No. 4 & Conservation Appeals

  • Assessing needs and requirements for common-mode education & operator training

  • Started the process to coordinate gas & electric: maintenance, operations & emergency communications


Teac22

Electric & Gas Coordination & Communications

  • Rolling Blackouts & System Restoration:

    • Assure that OP7 invocation will not impact critical pipeline or LDC facilities (w/focus on peak-shaving)

    • System Restoration Working Group - foundation work done by Levitan under ISO-NE Phase II Gas Study

    • Enhance existing operating procedures and protocols (OP6 & OP11) to formalize operator communications during emergencies


Teac22

Electric & Gas Coordination & Communications

  • Maintenance Coordination:

    • Initial meetings between ISO and gas industry to coordinate annual maintenance requirements between pipelines/LDCs and the electric sector.

    • Notify ISO of short-term gas-side maintenance via pipeline & LDC EBBs

    • Need to establish a protocol with Distrigas LNG


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Electric & Gas Coordination & Communications

  • Operations Coordination:

    • Establishing ISO access to pipeline EBBs (or e-mail or fax notification) to give advance notification of pipeline capacity constraints

    • Emergency Communications – updating bilateral contact information and develop ongoing dialogue between industry operating personnel


Teac22

Electric & Gas Coordination & Communications

  • Operator & Forecaster Training

    • Understand the pipeline grid and the nature of Capacity Constraints, OFOs, & Critical Notices

    • Understand the ramifications of generator contracting practices

  • Provide ongoing common mode training for gas & electric system operations personnel


Teac22

Electric & Gas Coordination & Communications

  • Support further coordination through participation in:

    • NERC - GEITF

    • NAESB - GECTF

  • Establish a new Electric & Gas Operations Committee which will facilitate the activities identified through the Electric & Gas Wholesale Initiative process


Teac22

Questions?


Rtep04 fuel diversity analysis

RTEP04 Fuel Diversity Analysis

TEAC 22 Presentation

June 2, 2004

Peter Wong ISO-NE

Power Supply & Reliability


Rtep04 fuel diversity analysis1

RTEP04 Fuel Diversity Analysis

The objective of this fuel diversity analysis is to investigate the impact on system resource adequacy due to potential fuel shortages, covering 2004 through 2013, assuming:

  • Fixed NEPOOL generation capacity

  • Currently known static transmission constraints


Rtep04 fuel diversity analysis2

RTEP04 Fuel Diversity Analysis

Several natural gas shortage scenarios were simulated assuming the shortage of gas fired generation in New England and the Sub-areas of NOR, SWCT and NEMA/Boston.

The analysis simulated system conditions on an annual basis to facilitate system modeling. Annual simulations allow results to be tabulated in various forms (annual, seasonal, monthly, etc.) as deemed appropriate.


Rtep04 fuel diversity analysis3

RTEP04 Fuel Diversity Analysis

System load, generating capacity and static transmission interface limit assumptions are consistent with RTEP04 MARS (reliability) simulations. TEAC20 and TEAC21 presentations summarize these assumptions. Copies of these presentations are posted on the ISO-NE web site under Quick Links (Transmission Expansion Advisory Committee).


Rtep04 fuel diversity analysis4

RTEP04 Fuel Diversity Analysis

Assumed Transmission Import Capability

Existing Import Capability:

  • NOR – 1,100 MW

  • SWCT – 2,000 MW

  • CT – 2,200 MW

  • NEMA/Boston – 3,600 MW

    Proposed Upgrades:

    SWCT Phase I:

    • NOR – 1,300 MW

    • SWCT – 2,550 MW

      SWCT Phase II:

    • NOR – 1,650 MW

    • SWCT – 3,400 MW

      NEMA/BOSTON Import:

    • NEMA/Boston – 4,500 MW

      CT Import:

    • CT – 3,200 MW


Rtep04 fuel diversity analysis5

RTEP04 Fuel Diversity Analysis

NEPOOL Installed Capacity Mix


Teac22

NEPOOL Installed Capacity by Fuel Type MW & %

The amount does not reflect settlement only units.


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NB - NE

NB - NE

Phase II

Phase II

HQ

NB

Orrington South

Orrington South

Highgate

Highgate

VT

Surowiec

South

Surowiec

South

ME - NH

ME - NH

East - West

East - West

BHE

ME

S-ME

NH

Boston

Boston

North - South

North - South

NY - NE

NY - NE

BOSTON

CMA/

W-MA

NEMA

NY

SEMA/RI

SEMA/RI

Connecticut

Connecticut

SEMA

SEMA

CT

CSC

CSC

RI

SEMA

South West

South West

CT

CT

Nuclear

NOR

SWCT

Coal

Gas

Oil

Hydro

Norwalk - Stamford

Norwalk - Stamford

Pumped Hydro

MISC

2004-2013 Sub-area Installed Capacity by Fuel Type- MW


Nepool sub area installed capacity by fuel type

NEPOOL Sub-area Installed Capacity by Fuel Type


Rtep04 fuel diversity analysis6

RTEP04 Fuel Diversity Analysis

Cases Simulated for this

Year’s Analysis Effort


Rtep04 fuel diversity cases new england region

RTEP04 Fuel Diversity CasesNew England Region


Rtep04 fuel diversity cases nor and swct sub areas

RTEP04 Fuel Diversity CasesNOR and SWCT Sub-areas


Rtep04 fuel diversity cases nema boston sub area

RTEP04 Fuel Diversity CasesNEMA/Boston Sub-area


Rtep04 fuel diversity analysis7

RTEP04 Fuel Diversity Analysis

Results

of

LOLE Reliability Simulations


Teac22

RTEP04 Fuel Diversity Analysis

New England Regional Results (LOLE in days/yr)

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

Note: Attainment of a 0.10 days per year (or lower) LOLE criterion does not ensure reliability. There may still be any number of reliability concerns that traditional deterministic and detailed system assessment methods are designed to identify.


Teac22

RTEP04 Fuel Diversity Analysis

New England Regional Results (LOLE in days/yr)

Note: Attainment of a 0.10 days per year (or lower) LOLE criterion does not ensure reliability. There may still be any number of reliability concerns that traditional deterministic and detailed system assessment methods are designed to identify.

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


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RTEP04 Fuel Diversity Analysis


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RTEP04 Fuel Diversity Analysis


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RTEP04 Fuel Diversity Analysis

New England Regional Results (LOLE in days/yr)

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

Note: Attainment of a 0.10 days per year (or lower) LOLE criterion does not ensure reliability. There may still be any number of reliability concerns that traditional deterministic and detailed system assessment methods are designed to identify.


Teac22

RTEP04 Fuel Diversity Analysis

New England Regional Results (LOLE in days/yr)

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

Note: Attainment of a 0.10 days per year (or lower) LOLE criterion does not ensure reliability. There may still be any number of reliability concerns that traditional deterministic and detailed system assessment methods are designed to identify.


Teac22

RTEP04 Fuel Diversity Analysis


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RTEP04 Fuel Diversity Analysis


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RTEP04 Fuel Diversity Analysis

New England Regional Results (LOLE in days/yr)

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

Note: Attainment of a 0.10 days per year (or lower) LOLE criterion does not ensure reliability. There may still be any number of reliability concerns that traditional deterministic and detailed system assessment methods are designed to identify.


Teac22

RTEP04 Fuel Diversity Analysis


Teac22

RTEP04 Fuel Diversity Analysis


Air emissions analysis

Air Emissions Analysis

A Presentation to the

Transmission Expansion Advisory Committee

Scott Hodgdon

June 2, 2004


Objective

Objective

  • Quantify the amount of aggregate generating unit air emissions (SO2, NOX, and CO2) in select scenarios investigated within RTEP04

    • Capacity scenarios

    • Transmission interface limit scenarios

    • Fuel price scenarios

    • Sub-area incremental/decremental load scenarios

      • TBD

    • Unit generation results obtained from IREMM results


Emission rate assumptions

Emission Rate Assumptions

  • Units of lbs/MWh

  • Obtained from various sources

    • US EPA (Scorecard and Egrid2002)

    • Existing ISO-NE Data

    • Similar type units

  • MA and CT State regulations/legislations modeled

    • Effect on emission rate changes illustrated

  • State Renewable Portfolio Standards not explicitly modeled


Emission rate assumptions1

Emission Rate Assumptions

Connecticut State Legislations/Regulation Assumptions


Teac22

Emission Rate Assumptions

Massachusetts Compliance Standards and Dates

  • Compliance path is the dates that a station is scheduled to meet the state emission standards.

  • Generating stations compliance path depicted by their Emission Control Plans (2 stations on Path I and 4 on path 2)

  • CO2 Standards noted in MA 310 CMR to not modeled due to various means to comply.


Scenarios

Scenarios

  • Base assumptions (fuel cost based generator bids)

  • Base with 1,492 MW of assumed retirements

  • Base with 1,156 MW of assumed unit additions

  • Base with combination of assumed retirements and additions

  • Base assuming constant cost of Natural Gas

    • Does not decline over study period


Scenarios1

Scenarios

  • Unconstrained case

  • Base with increases in various transmission limits

    • Boston

    • SWCT Phase I and II Projects

    • ME Internal Limits and ME-NH limit

  • Incremental and decremental load cases using on Base Case Assumptions

    • TBD


Case listing

Case Listing


Case listing1

Case Listing


Transmission assumptions

Transmission Assumptions

Case Transmission Assumptions (MW)

Yellow highlights changes from Base


Results 10 year totals so 2

Decrease from Base due to new generation and retirement assumptions

Increase from high gas price compared to Base Scenario

Base

Results – 10 year Totals – SO2


Results 10 year totals co 2

Decrease from Base due to new generation assumptions

Increase from high gas price compared to Base Scenario

Base

Results – 10 Year Totals – CO2


Results 10 year totals no x

Decrease from Base due to new generation and retirement assumptions

Increase from high gas price compared to Base Scenario

Base

Results – 10 Year Totals – NOX


Results 10 year totals

Results– 10 Year Totals

  • State Regulations significantly reduce total emissions.

  • Retirements of capacity with higher emission rates coupled with addition of new gas-fired capacity decreases emissions when compared to Base Case.

  • Higher gas prices lead to a significant increase in NEPOOL air emissions of SO2, NOX, and CO2 when compared to Base Case.

  • Transmission improvements from Base assumptions provide marginal benefits in terms of NEPOOL air emissions of SO2, NOX, and CO2.


Results annual totals so 2

Results – Annual Totals – SO2

Phases of Compliance

Path I and II MA

SO2 Regulations

Assumes Units Comply with State Emission Standards


Results annual totals co 2

Results – Annual Totals – CO2

Assumes Units Comply with State Emission Standards


Results annual totals no x

Results – Annual Totals – NOX

Compliance

Path II MA

NOX Regulations

Assumes Units Comply with State Emission Standards


Results annual totals

Results – Annual Totals

  • SO2 & NOX declining throughout time period due to more efficient/cleaner combined cycle usage coupled with assumed reductions to achieve state regulations.

  • CO2 increases as a result of energy consumption increase. CO2 mostly a byproduct of efficiency in generators.

  • Highest annual emissions realized in Case 3 where natural gas costs remain high compared to the Base Case.


So 2 state totals constant emission rates

SO2 State Totals – Constant Emission Rates

Base case results


Co 2 state totals constant emission rates

CO2 State Totals – Constant Emission Rates

Base case results


No x state totals constant emission rates

NOXState Totals – Constant Emission Rates

Base case results


So 2 state totals compliant emission rates

SO2 State Totals – Compliant Emission Rates

Base case results


Co 2 state totals compliant emission rates

CO2 State Totals – Compliant Emission Rates

Base case results


No x state totals compliant emission rates

NOX State Totals – Compliant Emission Rates

Base case results


Teac22

Questions?


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Impacts of Renewable Portfolio Standards (RPS) on NE Energy Supply

Presentation at TEAC 22

Jim Platts

June 2, 2004


Background

Background

  • As part of deregulation legislation in the late 1990s three New England states CT, MA, and ME established Renewable Portfolio Standards (RPS)

  • The RPS requires that a fixed or increasing percent of annual energy (MWH) supplied by LSEs be from renewable energy sources

  • RI and VT are also developing legislation to establish RPS


Connecticut rps

Connecticut RPS

  • CT RPS defines 2 classes of renewable technologies:

  • Class I: Solar, wind, fuel cells, landfill methane, ocean thermal, wave or tidal energy, low emission advanced renewables, small hydro, biomass

    • In 2004 1% of LSE supply must be Class I renewables growing to 7% by 2010.

    • Biomass must have begun operation after 7/1/98

  • Class II: Trash to energy, other biomass, other hydro

    • In 2004 and thereafter an additional 3% of LSE supply must be Class II, or Class Irenewables


Connecticut rps cont

Connecticut RPS (cont)

  • Applies to all LSEs except municipals

  • Can be met from renewable projects within New England, or NY, PA, NJ, MD or DE if their RPS is comparable. No deliverability required – can buy renewable energy credits

  • Penalty of $55/MWH for compliance failure which supports a renewable fund


Massachusetts rps

Massachusetts RPS

  • Defines renewables as: solar thermal, photovoltaic, wind, advanced biomass, fuel cells with renewable fuels, landfill gas, ocean thermal, wave, and tidal power

  • Requires:

    • In 2004, 1.5% of LSEs’ energy must be renewables growing to 4% by 2009

    • After 2009, renewables must increase by + 1%/yr

    • Can only be renewables installed after 1997


Massachusetts rps cont

Massachusetts RPS (cont)

  • Municipals are exempt

  • Renewable energy from outside ISO NE must demonstrate deliverability

  • Alternative compliance payment of $50/MWH if requirement is not met


Maine rps

Maine RPS

  • All LSEs in Maine

  • Defines renewables as:

    • SPP 80 MW plant or less using biomass and waste as only primary fuel source

    • Solar, wind, geothermal, hydro, biomass, fuel cells, tidal power or MSW with recycling in 100 MW plants or less. Cogeneration also qualifies.

  • Requires competitive electric supplier to have 30% renewables. Can average over 2 years


Maine rps cont

Maine RPS (cont)

  • Exemptions: suppliers to Pine Tree Zones

  • Can use NEPOOL GIS REC certificates to satisfy requirement

  • Failure to comply can result in

    • License revocation

    • Monetary penalties or

    • Optional payment to renewable research fund

  • Maine renewables currently exceed the 30% standard


Vt and ri rps

VT and RI RPS

  • VT: PSB Bill in legislature

  • RI: Bill in Legislature similar to MA RPS

  • NH: No active legislative proposal


Ne renewable generation 2000 03

NE Renewable Generation 2000-03

Source ISO New England - GWH


Rps requirements ct ma

RPS Requirements CT & MA

Annual GWH


New renewables required

New Renewables Required

  • Existing renewables in Maine exceed ME RPS requirements and CT’s meet it’s Class II requirements

  • New RPS demand is mainly from MA RPS and CT Class I requirements: ~5100 GWH by 2010

  • RPS in VT and RI could increase demand for renewables

  • Many factors can influence renewable supply e.g oil and gas prices, Prod Tax Credit, etc.


Ne rps supply wind projects

NE RPS Supply – Wind Projects

  • 10 projects are in the ISO NE SIS Queue for Generator Interconnection Studies

  • They total 885 MW. Cape Wind is 425 MW

  • At a 25% capacity factor these 10 would produce about 2000 GWh – a potential short fall of over 3000 GWh to meet the new RPS requirements.

  • Only Reddington Wind Project (30 MW) has a “conditional” approved 18.4.


Estimates of renewable costs

Estimates of Renewable Costs

Source: D. Luria, NECA Conference 3/18/04


Teac22

Questions?


Rtep04 resource adequacy deterministic analysis

RTEP04 Resource Adequacy Deterministic Analysis

TEAC22 Presentation

June 2, 2004

Peter Wong ISO-NE

Power Supply & Reliability


Rtep04 operable capacity analysis

RTEP04 Operable Capacity Analysis

The objective of this Deterministic Operable Capacity Analysis is to present a different way to review resource adequacy. The results show the expected operable capacity situation for the summer and winter seasons of 2004 through 2008/09, assuming:

  • Fixed NEPOOL generation capacity (similar to RTEP04)

  • Assumed planned and unplanned outages

  • No internal transmission constraints

  • Approximately 5,400 MW of gas generation assumed not available during the winter.


Rtep04 operable capacity analysis1

RTEP04 Operable Capacity Analysis

The Operable Capacity Analysis simulates system conditions on a weekly basis for two peak load scenarios – the loads with a 50% (50/50 load forecast) chance of being exceeded and the loads with a 10% (90/10 load forecast) chance of being exceeded. Results are presented for the entire season to facilitate the review.


Rtep04 operable capacity analysis2

RTEP04 Operable Capacity Analysis

Definition of Terms

  • Installed Seasonal Claimed Capability (SCC) – Total NEPOOL generation assumed to be in service per December 1, 2003 SCC Report, adjusted for 777 MW of new generation and 346 MW of retirements/deactivations.

  • Interchange – Reflect the amount of net of purchases and sales with neighboring Control Areas reported to the ISO.

  • New Generation – Same unit addition assumption used for the probabilistic reliability assessments. See amount listed above.

  • De-listed ICAP Resources – De-listed ICAP quantities are only known with certainty in the current month and therefore, do not appear in these analyses.

  • Net Capacity = (SCC) + (Interchange) + (New Generation) – (De-listed ICAP Resources)


Rtep04 operable capacity analysis3

RTEP04 Operable Capacity Analysis

Definition of Terms

  • Peak Load Exposure – The expected seasonal peak loads as published in the April 2004 CELT report and assumed to occur in every week of the denoted summer (13 weeks starting with the first full week of June) and winter (3 weeks starting with the first full week in January, not inclusive of the week with the New Year’s holiday) periods. Please note that in reality, the forecast peak would most likely occur once or twice during a season.

  • Operating Reserve Requirement – The amount of operating reserve assumed to be carried by the system for real time control. Typically, it is assumed to be 1.0 times the largest generator contingency loss plus 0.5 times the second largest contingency loss.

  • Total Known Maintenance – The amount of long-term generator maintenance as approved by ISO-NE. Only summer 2004 values reflect actual approved maintenance. For winter 2004/2005 through winter 2008/09, the generator maintenance reflect assumed estimates.


Rtep04 operable capacity analysis4

RTEP04 Operable Capacity Analysis

Definition of Terms

  • Allowance for Unplanned Outages – The amount of generator forced outages and maintenance outages scheduled less than 14 days in advance. The assumed values are based on an analysis of historical unit performance.

  • Assumed Gas Unit Unavailability – The amount of gas-fired generating units assumed to be unavailable during December through March based on the events of the January 14, 2004 Cold Snap.

  • Total Capacity – The amount of generating capacity available to meet the demand calculated as follows: (Net Capacity) – (Total Known Maintenance) – (Allowance for Unplanned Outages) – (Assumed Gas Unit Unavailability).

  • Operable Capacity Margin – The amount of projected weekly capacity margin. A positive value indicates a potential surplus of operable capacity over and above the estimated load plus operating reserve requirement. A negative value indicates a potential operable capacity deficiency.


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RTEP04 Operable Capacity Analysis

Operable Capacity Analysis Results


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis

2004/2005 Winter


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis

2005/2006 Winter


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis

2006/2007 Winter


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis

2007/2008 Winter


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis

2008/2009 Winter


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis


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RTEP04 Operable Capacity Analysis

Assumed 5,400 MW of gas fired units unavailable.


Rtep04 operable capacity analysis5

RTEP04 Operable Capacity Analysis

Observations (Summer)

  • NEPOOL is expected to have adequate operable capacity through the summer of 2008 study period to meet the 50/50 load forecast.

  • NEPOOL could experience negative operable capacity margin as early as the summer of 2005 if loads associated with hot and humid weather (94 degrees F) occur and a high amount of generation is out of service. The extent of the operable capacity deficiency would depend on the amount of generating unit forced outages at the time.

  • The availability of the generating resources during the summer is crucial to assure a reliable bulk power supply system.

  • While negative operable capacity margin could occur during the study period, load relief from Operating Procedure no. 4 – Action During a Capacity Deficiency (OP 4) should be sufficient to mitigate the expected problem.


Rtep04 operable capacity analysis6

RTEP04 Operable Capacity Analysis

Observations (Winter)

  • NEPOOL could experience negative operable capacity margin during extreme cold weather conditions when loads reach the levels associated with the 90/10 forecast, assuming half of the gas capable units are out of service.

  • Normally, NEPOOL OP 4 Actions are not expected during the winter season, given that NEPOOL is a summer peaking system and adequate installed capacity exists to meet the winter peak. However, possible lack of gas to fuel generating resources could impact NEPOOL system reliability and could cause the need to implement OP 4.

  • The availability of gas unit generation is essential during the winter to maintain system reliability.


Rtep04 operable capacity analysis7

RTEP04 Operable Capacity Analysis

Questions?


New england capacity outlook presentation made to the necpuc on may 26 2004

New England Capacity OutlookPresentation made to the NECPUC on May 26, 2004

TEAC22

Wednesday, June 2, 2004

Radisson Hotel

Marlborough, Massachusetts


New england capacity situation

New England Capacity Situation

  • More than 9,000 MW of capacity added since 1999

  • Today’s surplus capacity situation is short-lived. Serious conditions in load pockets need to be addressed now.

    • Certain resources are critical within load pockets – not only to serve load, but also to provide contingency coverage, transmission support and allowance for construction and maintenance outages

  • Some generating units needed for system reliability are ‘at risk’

  • Even with planned transmission upgrades in load pockets, additional resources will be needed within the load pocket to offset retirements and limits on operation of existing units

  • Without additional resources, generation unit attrition and a lack of fuel diversity will jeopardize resource adequacy in New England

  • Nearly 16,000 MW of capacity in New England is gas-capable, of which more than 8,000 MW is gas-only


Near term outlook

To have resources online for…

Plan now

Near-term Outlook

  • Two major areas of concern in New England for resource adequacy: Connecticut and Boston

  • Critical timing situation for these areas

    • With major transmission upgrades in the pipeline, action is required now to be prepared for near-term supply issues: potential generation retirement and opportunities for re-powering

    • Emergency RFP needed in cases when an area is already deficient


Longer term outlook

Longer-term Outlook

  • New England supply outlook shifts from tight to deficit conditions over the next decade under both expected and higher-than-expected peak load conditions

    • Reliability gap appears in 2011 under expected peak load conditions (50/50), and continues to grow

    • Reliability gap appears in 2006 under higher-than-expected peak load conditions (90/10), and continues to grow. We must have a plan to meet the 90/10 forecast.


Required actions

Required Actions

  • Actions must begin now to assure future reliability:

    • Transmission improvements in load pockets

    • Market enhancements to encourage:

      • New generation resources with consideration for fuel diversity

      • Demand response

      • Dual-fuel investments in existing capacity


New england capacity outlook

50/50 Peak + 2,000 MW Forced Outages + Operating Reserves

90/10 Peak + 2,000 MW Forced Outages + Operating Reserves

New England Capacity Outlook

35,000

32,500

30,000

27,500

25,000

Capacity/Peak Load (MW)

22,500

20,000

17,500

15,000

12,500

10,000

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

Year

Capacity


Generation at risk

Generation ‘At Risk’

  • Risk categories that could result in generation attrition or outages:

    • Age: Units that have been in service for more than 40 yrs.

    • Environmental: Units that may need significant investment to meet environmental regulations

    • Financial: Units that are not economic (newer and older units)

      • Energy market revenues not sufficient to sustain all existing units or to attract investment

    • Gas: Units that are fueled exclusively by natural gas


Major concerns

Major Concerns

  • Major problem areas:

    • Connecticut

    • Northeastern Massachusetts (NEMA)/Boston

  • Transmission investment has not been keeping up with growth in demand resulting in internal transmission constraints

  • Several requests to deactivate or retire generation

    • Limited ability to connect new generation

  • Time is our enemy. Even if the transmission comes in on schedule, load growth will dictate a very tight window to accommodate re-powering of existing sites.


Connecticut

Connecticut

  • Demand plus reserve requirements outstrip supply in 2004 (and beyond)

    • 7,400 MW demand (90/10) + 1,200 MW reserve requirement = 8,600 MW

    • 6,000 MW net generating capacity + 2,200 MW import limit = 8,200 MW

      • 900 MW of capacity is gas-only

  • Emergency resources and special operating procedures are needed to keep the lights now in SWCT

  • Existing generation is needed to provide bulk power system support

  • 345 kV loop relieves transmission constraints within CT

  • 345 kV link to Massachusetts and Rhode Island is necessary to increase CT import limit

  • Transmission will not eliminate need for additional capacity given potential for generating unit retirements. Transmission must be completed on schedule so that existing sites can be re-powered.


Connecticut capacity situation

Assumed CT Import Limit Increase from 345 kV East/West

10,000

9,000

8,000

7,000

6,000

5,000

Summer MW

4,000

3,000

2,000

1,000

-

2004

2005

2006

2007

2008

2009

2010

2011

2012

Net Operable Capacity

(including Forced Outages)

* Excludes Emergency Capability RFP MW

* Assumes 90/10 Peak Loads

Load + Reserves

Capacity (MW)

Import Capacity MW

Connecticut Capacity Situation


Nema boston

NEMA/Boston

  • NEMA/Boston has the highest electricity use in New England

  • Retirement or deactivation of units drives need for replacement supply – no new generation proposed

    • Downtown: Mystic Units now retired (400 MW)

    • Downtown: New Boston Station (350 MW) denied retirement

    • North Shore: Salem Harbor Station (740 MW) denied retirement

    • Western Suburbs: Kendall Station (220 MW) requested deactivation

  • Recent large capacity additions solely dependent on LNG imports (Mystic 8 & 9: 1,400 MW combined)

  • NSTAR transmission upgrade is necessary to import capability

  • North Shore transmission upgrades are necessary for local reliability

  • 1,600 MW of capacity is gas-only


Nema boston capacity situation

NEMA/Boston Import Limit Increase from 345 kV Upgrade

9,000

8,000

7,000

6,000

5,000

Summer MW

4,000

3,000

2,000

1,000

-

2004

2005

2006

2007

2008

2009

2010

2011

2012

Net Operable Capacity

(including Forced Outages)

Load + Reserves

* Assumes 90/10 Peak Loads

Capacity (MW)

Import Capacity MW

NEMA/Boston Capacity Situation


Vermont

Vermont

  • Lack of resources in Northwest Vermont (NWVT) creates possible reliability problems

    • Loss of transmission into NWVT could mean interruption of load

  • Planned 345 kV transmission upgrades in NWVT are necessary for reliability and to improve access to generation


Other new england states

Other New England States

Maine:

  • Transmission export constraints create up to 750 MW of bottled capacity in Maine and New Brunswick

  • The addition of a second New Brunswick tie would:

    • Establish the first section of a 345 kV path through Maine to NEMA

    • Reduce losses by 23 MW

    • Increase export capability from Maine to New Brunswick and from New Brunswick to Maine

      New Hampshire and Rhode Island:

  • Generation capacity exceeds demand in both states

  • Local transmission concerns are under review in both states


Actions needed for load pockets

Actions Needed for Load Pockets

  • Complete transmission infrastructure

  • Re-power older, inefficient units with dual-fuel peaking capacity

  • Increase demand response and conservation

    • Gap RFPs are needed in certain cases to obtain demand response/temporary emergency generation

  • Add new resources to accommodate demand growth

    There is a brief window of time to get this done. It will take a well coordinated effort by state policymakers, the ISO and market participants to make this happen.


Background information

Background Information


Capacity plan identified actions connecticut

Capacity Situation

(Summer MW)

2004

2005

2006

2007

2008

2009

2010

2011

2012

Load (90/10 Forecast)

7,435

7,575

7,645

7,690

7,790

7,840

7,940

8,060

8,180

Reserves (largest unit)

1,200

1,200

1,200

1,200

1,200

1,200

1,200

1,200

1,200

Total Requirement

8,635

8,775

8,845

8,890

8,990

9,040

9,140

9,260

9,380

Capacity

6,927

6,927

6,927

6,927

6,927

6,927

6,927

6,927

6,927

Assumed Forced Outages

470

470

470

470

470

470

470

470

470

Transmission Constrained MW

223

223

223

223

-

-

-

-

-

Peaking Unit Deratings

219

219

219

219

219

219

219

219

219

Total Net Capacity

6,015

6,015

6,015

6,015

6,238

6,238

6,238

6,238

6,238

Current Import Limit

2,200

2,200

2,200

2,200

2,200

2,200

2,200

2,200

2,200

Total Available Resources

8,215

8,215

8,215

8,215

8,438

8,438

8,438

8,438

8,438

Available Surplus/(Deficiency)

(420)

(560)

(630)

(675)

(552)

(602)

(702)

(822)

(942)

Identified Actions

(Summer MW)

2004

2005

2006

2007

2008

2009

2010

2011

2012

Emergency Actions

EC RFP (Award)

125

218

250

256

-

-

-

-

-

Operating Procedure (Load Swap)

340

340

340

340

340

340

340

340

340

Strengthening of System

SWCT Phase I

(Increase to CT Import Limit)

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

SWCT Phase II

(Increase to CT Import Limit)

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

East/West 345 kV

(Increase to CT Import Limit)

-

-

-

-

800-1,000

800-1,000

800-1,000

800-1,000

800-1,000

Total Identified Actions

465

558

590

596

1,140 - 1,340

1,140 - 1,340

1,140 - 1,340

1,140 - 1,340

1,140 - 1,340

Capacity Plan & Identified Actions: Connecticut

NOTE: - Generation within CT is restricted by internal transmission constraints


Capacity plan identified actions nema boston

Capacity Plan & Identified Actions: NEMA/Boston

Capacity Situation

(Summer MW)

2004

2005

2006

2007

2008

2009

2010

2011

2012

Load (90/10 Forecast)

5,620

5,765

5,830

5,900

5,965

6,030

6,105

6,200

6,270

Reserves (largest unit)

710

710

710

710

710

710

710

710

710

Total Requirement

6,330

6,475

6,540

6,610

6,675

6,740

6,815

6,910

6,980

Capacity

3,602

3,602

3,602

3,602

3,602

3,602

3,602

3,602

3,602

Assumed Forced Outages

244

244

244

244

244

244

244

244

244

Peaking Unit Deratings

82

82

82

82

82

82

82

82

82

Total Net Capacity

3,276

3,276

3,276

3,276

3,276

3,276

3,276

3,276

3,276

Imports

3,600

3,600

3,600

3,600

3,600

3,600

3,600

3,600

3,600

Total Available Resources

6,876

6,876

6,876

6,876

6,876

6,876

6,876

6,876

6,876

Available Surplus/(Deficiency)

546

401

336

266

201

136

61

(34)

(104)

Identified Actions

(Summer MW)

2004

2005

2006

2007

2008

2009

2010

2011

2012

Emergency Actions

Operating Procedure (Load Swap)

50

50

50

50

50

50

50

50

50

Strengthening of System

345 kV Upgrade

-

-

900

900

900

900

900

900

900

Total Identified Actions

50

50

950

950

950

950

950

950

950


Teac22

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Planning studies update

Planning Studies Update

Presented atTEAC22

June 2, 2004

Rich Kowalski – ISO New England


Planning studies update1

Planning Studies Update

Burlington Vermont Area

Vermont Southern Loop

Monadnock RegionLogan Airport AreaNortheast Massachusetts

King Street Area SupplySouthwest Rhode Island


Burlington vermont area

Burlington Vermont Area

115kV Loop Supply


Performance assessment

Performance Assessment

  • The completion of the NWVT project and the new Tafts Corners substation still leaves a portion of Burlington fed by a radial 115kV line through a single distribution transformer.

  • This area, which includes the Burlington Medical Center, the University of Vermont, and a major portion of the downtown area has outgrown the 34.5kV system. A single failure creates a sustained outage to critical customers.


Summary of alternatives

Summary of Alternatives

  • 34.5kV alternatives have been eliminated.

  • The two 115kV alternatives (very similar cost to the 34.5kV alternatives) offer less lines and line work and more desirable station upgrades.

  • Both 115kV plans loop into East Avenue Sub, but the preferred has the added benefit of rebuilding the old Gorge Substation and two 34.5 feeders.


Progress update

Progress Update

  • Study work continues with the expectation that the preferred plan will be selected.

  • 18.4 / 12C applications scheduled to be made during the summer period.


Vermont southern loop analysis update

Vermont Southern Loop Analysis Update


Performance assessment1

Performance Assessment

  • Need to serve load growth along a 66 mile long 46 kV line; loss of 46kV line sections or loss of the VY-Vernon Road-Chestnut Hill 115 kV line can result in voltage collapse and inability to serve load until repairs can be made.


Performance assessment2

Performance Assessment

  • Seeks to significantly improve service reliability for load pockets in SW VT (Bennington), SE VT (Brattleboro) and SW NH (Keene).

    • 100+ MW of CVPS load in southern VT

    • 130+ MW of PSNH load in SW NH (Chestnut Hill to Keene to Monadnock to Jackman)

    • Station service / cooling tower loads for Vermont Yankee (115 kV @ VY – up to 25.5 / 8.5 MW respectively)


Teac22

  • INFORMATION REDACTED DUE TO SECURITY CONCERNS


Summary of alternatives1

Summary of Alternatives

  • Alternatives include the following:

    a)Synchronous condensers along the 46 kV loop

    b)Connecting the 46 kV loop to the 340 line

    c)Combining alternatives a) and b)

    d)Replacement of the 46 kV loop with a 115 kV line, with the attendant station changes along the 46 kV loop (potentially twelve different stations)

    e)Replacement of the 46 kV loop with a double circuit 115/46 kV line. This option requires no changes to the dozen load serving stations presently along the 46 kV loop.


Teac22

Summary of Alternatives

f)Replacement of a portion of the 46 kV loop (from Bennington approximately half way to Brattleboro) and then connect the 115 kV line to the 340 line.

g)A variation on alternative f) where the eastern end of the new line instead terminates at VELCO’s Coolidge station.

  • Alternatives d and e will consider different sites for the eastern end termination including the Vermont Yankee and Vernon Road stations.

  • Preliminary testing has indicated that alternatives a, b and c do not provide acceptable levels of performance. It also has shown that combining alternatives d and e with g can provide broader area system benefits beyond the immediate need timeframe.


Preferred alternative so far

Preferred Alternative So Far. . .

  • Likely to be “phased”

    • Phase 1 addresses most significant local reliability concerns

    • Phase 2 addresses longer term reliability issues

  • Double circuit 115 / 46 (part of phase 1)

    • 56 miles from Bennington to West Dummerston (a station adjacent to the 340 line ROW)

  • Single circuit 115 - single pole / delta construction (line to VY part of phase 1, line to Coolidge part of phase 2)

    • From Vermont Yankee to Coolidge


Teac22

Preferred Alternative So Far. . .

  • New stations at Stratton and Dummerston (part of phase 1)

    • In & out breakers at Stratton to accommodate a 115/46 auto

    • Ring bus at Dummerston to accommodate three 115 kV lines (from Bennington, Coolidge and VY) and a 115/46 auto

  • Station changes at Bennington and Vermont Yankee (part of phase 1)

    • At Bennington add a line breaker and bus tie breaker (at least)

    • At Vermont Yankee add a line breaker (at least)


Estimated cost of what might become the preferred alternative

Estimated Cost of What Might Become the Preferred Alternative

  • Total cost – PTF & non PTF - $46.2M

    • PTF portion @ $36.2M

    • Non PTF portion @ $10M


Progress update1

Progress Update

  • Alternatives performance assessment currently underway; should be complete in summer, 2004.

  • 18.4 / 12C process to start during summer, 2004.


Monadnock region reliability study

Monadnock RegionReliability Study


Performance assessment3

Performance Assessment

  • Voltage and thermal violations arise for several contingencies at a 27800 MW level

  • Worst cases:

    • Loss of Coolidge-VY 345kV line results in low voltage or voltage collapse from Middlebury to Ascutney

    • Loss of Pratts-Flagg Pond 115kV double circuit results in low voltage or voltage collapse from Bellows Falls-Flagg Pond

    • Loss of the VY 345-115kV autotransformer results in low voltages at and around VY / Vernon Road 115kV


Summary of alternatives2

Summary Of Alternatives

  • Upgrade Plan 1 ($76.8M)- Build a new 345/115 kV substation at Fitzwilliam, NH; reconductor the I‑135 115 kV line from Bellows Falls to Flagg Pond.

  • Upgrade Plan 2 ($71.6M)- Install a new dynamic VAR device at Coolidge; reconductor the I‑135 115 kV line from Bellows Falls to Flagg Pond.

  • Upgrade Plan 3 ($74.5M)– Add a new Webster 230 kV Substation in a five-breaker ring bus design with a single 230/115 kV autotransformer.


Teac22

Summary Of Alternatives

  • Upgrade Plan 4 ($138.9M)- Double‑circuit the existing 115 kV line from Webster to Ascutney with a new 230 kV line; construct a 230/115 kV Substation at Ascutney, VT, and a 230 kV 5‑breaker ring bus at Webster.

  • Upgrade Plan 5 ($142.0)- Build a Deerfield ‑ Webster ‑ Coolidge 345 kV line with a 345/230 kV transformer and two 345 kV breakers at a new Webster 345 kV Substation; add a Webster 230 kV Substation with a six‑breaker ring bus design; double‑circuit the 345 kV line and existing 115 kV line between Webster and Ascutney.


Progress update2

Progress Update

  • Cost estimates are still preliminary.

  • Additional refinements to the analyses are necessary:

    • Does Upgrade Plan 1 require dynamic shunt compensation?

    • How long beyond study time frame will the 795 ACSR conductor be good for?

    • Does the plan hold up for long term autotransformer outages?

  • Study work continuing.


Logan airport area transmission supply

Logan Airport AreaTransmission Supply


Area characteristics

Area Characteristics

INFORMATION REDACTED DUE TO SECURITY CONCERNS


Performance assessment4

Performance Assessment

  • 2006: Loss of the Golden Hills – Lynn 115kV line overloads the Mystic-Chelsea 115kV line.

  • 2008: Forecasted load (including additions at Logan Airport) in the East Boston-Chelsea region will exceed the Chelsea Station capacity.


Summary of alternatives3

Summary of Alternatives

  • Mystic –East Boston and East Boston-K Street 115kV lines

  • Mystic-East Boston-and East Boston Chelsea 115 kV transmission lines

  • Upgrade Mystic-Chelsea 115 KV line and Golden Hills-Lynn 115 kV line

  • 2nd Mystic-Chelsea 115 kV line


Progress update3

Progress Update

  • Comprehensive study work should begin this summer.


Northeast massachusetts area study

Northeast MassachusettsArea Study

National Grid’s

Merrimack Valley &

North Shore Districts


Performance assessment5

Performance Assessment

  • Portions of this area have been assessed from a transmission adequacy and operating reserve capacity perspective in the Boston Import / North Shore analyses.

  • This study will be a more localized assessment of system performance under various stressed conditions for the 2007 – 2017 time period.


Progress update4

Progress Update

  • Study is currently in early stages with results expected by the end of 2004.


King street area supply west amesbury substation

King Street Area Supply West Amesbury Substation


Performance assessment6

Performance Assessment

  • In 2006, the King Street substation’s firm capacity of 207 MW will be exceeded.

  • Thermal and voltage violations on the 115kV supply system

  • Inadequate coverage for 23kV system contingencies


Summary of alternatives4

Alternative

Relative Performance

Issues

Order of Magnitude Estimate

Extend 115 kV line from King Street to new W. Amesbury 115-23 kV substation

Addresses problems

New transmission line required

$11.5 Million

Add an additional 115-23 kV transformer at King Street and construct a new 23 kV substation

Extend a 115 kV line from King Street to a new W. Amesbury 115-13 kV substation

Addresses problems

New transmission line required

$13 Million

Extend two 115 kV lines from King Street to new 115-23 kV substation

Addresses problems

New transmission line required

$18.6 Million

Install a new 345-115 kV substation at W. Amesbury supplied from line 394 to supply a new 115-23 kV substation

Addresses problems; provides an additional supply to King Street

A portion of the load is supplied radially from W. Amesbury

$10.7 Million

Summary of Alternatives


Progress update5

Progress Update

  • Currently working on 18.4 analysis

  • Project scheduled for 2006 in-service date


Southwest rhode island

Southwest Rhode Island

The L-190 Project

Kent County - Davisville


Performance assessment7

Performance Assessment

  • SWRI area does not meet reliability standards at the 27400 MW load level

  • Loss of the Montville-Mystic section of line 1280 in CT results in:

    • Overloading of the G-185S line between Davisville Tap and West Kingston

    • Low voltages along the corridor


Summary of alternatives5

Alternative

Relative Performance

Issues

Order of Magnitude Estimate

Extend L-190 from Davisville tap to W. Kingston (2006)

Rebuild W. Kingston to include 115 kV ring bus (2006)

Reconductor L-190 (2006)

Reconductor G-185S (2012)

Addresses problems through 2020

Provides better reliability to load by connecting a third line at W. Kingston

$11 Million

Reconductor G-185S and install six 10 MVAR capacitor banks

Additional reinforcements needed in 2015

$16 Million

Reconductor G-185S and install 60 MVAR D-SMES

Additional reinforcements needed in 2015

$20 Million

Construct a new 345 kV line from Kent County to Montville and a 345-115 kV substation at or near W. Kingston

Addresses problems through 2020

$108 Million

Summary of Alternatives


Progress update6

Progress Update

  • Currently working on 18.4 analysis


Teac22

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