TEAC17 Thursday, July 10, 2003 Radisson Hotel

TEAC17 Thursday, July 10, 2003 Radisson Hotel
Marlborough, Massachusetts Redacted Version for Posting

TEAC17 Agenda Welcoming Remarks/Announcements
Natural Gas and Fuel Diversity Concerns Reliability Analysis – Fuel Diversity Results Environmental – Air Emission Impacts Congestion Analysis – Additional Sensitivities Interregional Issues Transmission Planning Study Update Resource Adequacy – Locational ICAP Modeling

TEAC Announcements Technical Session Limited Responses
Since TEAC16 ISO-NE sent MA DTE presentations to TEAC Planning Studies regarding potential 345 kV Upgrades in Boston, SEMA/RI &CT incomplete ISO-NE will again gauge interest mid- August

TEAC Announcements Fuel Diversity Working Group Formation
To Draft Scope Market Rules Guidance to RTEP Operating Procedure Guidance to Regulators Initial Meeting August 5th w/ NEPOOL RC TEAC Interest Contact at by July 25, 2003

TEAC Announcements TEAC18 Comments on RTEP03 Draft
Draft report will be sent, on August 1st, to those registered and requests made to Meeting to be held on August 14th (Thursday) Springfield MA location TBA

Natural Gas and Fuel Diversity Concerns in New England and the Boston Metropolitan Electric Load Pocket Mark Babula ISO-NE July 10, 2003

Executive Summary/Findings Adequacy of Natural Gas Resource Base
North American Gas Supply Outlook Outlook in Atlantic Canada Outlook on LNG Supply and Local Storage Gas Delivery in New England Infrastructure Adequacy Deliverability within the Boston Load Pocket Gas Pricing and Volatility in New England Volatility Trends in New England Electric Sector Impacts from High Prices New England’s Fuel Mix Portfolio Fuel Diversity Forecast: NEPOOL & Boston Area

Adequacy of Natural Gas Resource Base
Estimate of North American gas resource base = 1,900 Tcf Equates to 70 years of supply at 2002 consumption levels Current exploration & production (E&P) on a “treadmill effect” Drilling has more than doubled from 1996 to 2001, while total average gas production has increased only by 3.1%

Supply/Source Production Share of Total North Region (Bcf) American Production (%) Gulf Coast , Western Canada 5, Rocky Mountains , Mid-continent , Other * , Appalachia Atlantic Canada LNG Total , % Source = Natural Resources Canada, Canadian Natural Gas 2001 Market Review & Outlook, June & U.S. EIA/Natural Gas Monthly June 2002; Oil and Gas Journal * Includes Alaska, Pacific Coast, Illinois Basin, Michigan & Ontario

N. American depletion rates have increased at an accelerated rate Production has nearly remained constant since 1990 Depletion rates have been rising since 1990 U.S. depletion rate from 16% to 28% Canadian depletion rate from 16.5% to 23.5%

Outlook in Atlantic Canada
Current production from the Scotian Shelf is small in comparison to Gulf Coast & Western Canada 0.5 Bcf Scotian vs Gulf & 16.2 Western Canada Scotian shelf is in its infancy Less than 200 wells drilled Currently supporting roughly 20% of New England’s gas needs

Outlook in Atlantic Canada
Pipeline infrastructure poised for expansion EnCana has taken a regulatory “time-out” Next tranche of gas production likely in the 2008 – 2010 timeframe Scotian gas will flow to New England through 2020

Outlook on LNG Supply & Storage
LNG is a globally traded commodity Pacific rim is heavily dependent on LNG Over 850 Tcf of reserves: Qatar (500 Tcf), Algeria (160 Tcf), Nigeria (124 Tcf), Trinidad (25 Tcf) LNG set for major worldwide expansion – 150 tankers by 2005 Deep pockets required to play this game Only 4 terminals in US: Everett, MA = DOMAC/Distrigas Elba Island – GA / Lake Charles – LA / Cove Point - MD Total LNG sendout from all facilities = 1,050 Bcf by end of 2003

Outlook on LNG Supply & Storage
Poor geology in New England for underground gas storage – thus above ground LNG tankage Almost all of New England’s supply is from Trinidad Distrigas storage capability = 3.5 Bcf 14 other major satellite facilities around New England Manufacture on-site & truck shipments Total New England LNG storage capacity = 15.1 Bcf Mystic 8 & 9 – sole fuel source is Distrigas LNG Distrigas – susceptible to common-mode failures ?

Gas Delivery in New England
5 major interstate pipelines Proximity to Sable Island is a plus for New England New projects include M&N Phase III & Hubline Proposed projects: Deer Island Lateral & Everett Extension = A path to Mystic 8 & 9 & Distrigas

Gas Delivery in New England
Pipeline capacity still cannot serve coincidental winter loads Phase I Gas Study: steady-state analysis Phase II Gas Study: transient analysis By winter of 2004/2005, “generation-at-risk” approx 2,800 MW – 3,900 MW ISO-NE analysis had “idealized” assumptions about border gas supply

Winter Capacity (MW) of Gas Capable Units
Includes 2003 units: AES GRANITE RIDGE, MILFORD PDC, SITHE FORE RIVER, SITHE MYSTIC Information Source: 2003 NEPOOL CELT Report, April 2003

Gas Delivery in New England Winter Peak Day Gas-Fired Generation at Risk (MW)

Gas Delivery in New England Gas-Fired Generation Capacity Served by Pipeline (MW) (Winter 2004/2005)

Gas Delivery in Boston Load Pocket
KeySpan is the LDC for deliveries to in-city generators Mystic 8 & 9 – single fuel = LNG Everett Extension from Deer Island will provide operational flexibility and backup supply into Algonquin’s J system, esp. during winter Salem Harbor could get access to pipeline gas

Gas Pricing and Volatility in N. England
Increased volatility at Henry Hub/Dracut due to: Maturation of resource base Growing demand from electric sector Depletion of working gas storage Concern over storage injections for upcoming winter “Demand Destruction” – price will equalize this winter’s supply vs. demand imbalance i.e., trigger fuel switching

Growing off-peak demand by electric sector will compete with LDC injection gas for reservoir replenishment High prices through summer & fall and into winter 2003/2004 Volatility hear to stay until new gas supplies commercialized in upcoming years

Gas Pricing and Volatility in N
Gas Pricing and Volatility in N. England Comparative Fuel Costs Delivered to N.England Generators

Wholesale electricity prices linked to natural gas prices High gas prices affect dispatch of generation mix RFO can be economically substituted for gas at dual fuel steam units. However, these units are losing market share due to superior transformation efficiencies of the new merchant CC units Over 50% of all LMPs set by gas units Salem Harbor on gas would probably increase wholesale electric prices in the Boston sub-area

Gas Pricing and Volatility in N. England Real Time Marginal Price Setter by Fuel Type (Source = ISO-NE Quarterly Markets Reports, Public Version)

Gas Pricing and Volatility in N. England Real Time Marginal Price Setters by Unit Type (Source = ISO-NE Quarterly Markets Reports, Public Version)

Fuel Diversity in New England
Steady-State Analysis of New England’s Interstate Pipeline Delivery Capability, (Phase I – Jan 2001) Steady-State and Transient Analysis of New England’s Interstate Pipeline Delivery Capability, (Phase II – Feb 2002) RTEP02 (November 2003) & RTEP03 (ongoing) Natural Gas and Fuel Diversity Concerns in New England and the Boston Metropolitan Electric Load Pocket (July 2003) IMO Multi-Regional Gas Study (targeting completion – Sept 2003) Related reliability analyses: Loss of nuclear & gas units

Fuel Diversity in New England
Recent build-out of merchant generation will yield approx 10,700 MW of gas-fired capacity being commercialized by 2005 In 1999, gas-fired generation equaled 16% to total New England electric energy production By 2003, natural gas will fuel 41% of overall energy production By 2010, natural gas will fuel 49% of overall energy production Other than the state of Texas, New England is by far the most dependent region in North America on gas for power generation

Fuel Diversity in New England NERC Region Comparison: Generation by Fuel as % of Total (2002) (Source = EIA – Long Term Energy Forecast Supplemental Tables)

Fuel Diversity in Boston Load Pocket
Boston Import sub-region is transmission constrained Once Mystic 8 & 9 are commercialized, with Salem Harbor continuing to operate on coal & oil, natural gas accounts for 65% of all energy production in the Boston sub-area By 2010, reliance on natural gas will reach 80% (energy) If Salem Harbor were converted to fired gas, natural gas will fuel 94% of Boston sub-area energy production Boston’s gas requirements for electric power generation depend upon both pipeline gas & LNG

Fuel Diversity in Boston Load Pocket
Salem Harbor accounts for 85% of the total capacity in the North Shore sub-area Coal fired units usually committed in-merit order and help satisfy both North Shore must-run requirements and Boston Import area operating reserve requirements Salem Harbor needs to comply with MA 310 CMR 7.29 air regs ISO-NE assessing reliability implications from the 18.4 Applications to retire Salem Harbor station, Mystic 4, 5 & 6, and New Boston

White Paper Findings – Where to from Here?
Changes to State Statutes Market Rule Changes Gas Study Findings Task Force RTEP Projects ISO-NE Lead NECPUC Rep. NEPOOL Rep. NERC/NPCC/ NEPOOL Reliability Rule Changes Possible Outcomes

Executive Summary/Findings
1. Between 1998 – 2005, 10,700 MW of new gas-fired generation will become commercialized In 1999, 16% of New England’s electric energy production was by natural gas In 2003, 41% of energy production by gas By 2010, 49% of energy production by gas Other than the State of Texas, New England is 2nd most dependant region in North America on natural gas for power generation The transmission constrained metropolitan Boston Area is highly dependant on gas-fired generation Natural gas accounts for 65% energy production in sub-area (post commercialization of Mystic 8 & 9) Increased reliance to 80% by 2010 If Salem Harbor converted to gas, 94% reliance by 2010

3. E&P in the Gulf Coast and Western Canada are experiencing maturation of traditional supply basins Depletion rates accelerating (1990 – 16%, 2002 – 28%) Resource base remains immense, however, sustained production improvements will require massive investments, thus anticipating; higher commodity prices, increased price volatility, and higher trading bandwidths 4. The increase in gas production in Atlantic Canada will be delayed E&P around Sable Island has encountered significant set-backs, however, the supply basin is still in its infancy Next wave of supply unlikely to materialize before end 2008, probably by 2010 New England utilities and merchant generators will incur a premium to obtain incremental gas supplies from Gulf Coast or Western Canada

5. New England’s increasing dependence on gas exposes ratepayers to the impacts of high prices and volatility Wholesale electricity prices linked to value of natural gas, I.e. spark spreads Distrigas LNG helps tempers the run-up in winter basis differentials Distrigas figures prominently in maintaining energy security (electric & gas) 6. Prior ISO-NE gas infrastructure analyses indicate that there is not sufficient pipeline capacity within New England’s borders to meet coincidental gas requirements of gas utilities and merchant generators during the coldest part of the winter heating season ISO-NE Phase I Gas Study (Jan 2001) - Steady-state analysis ISO-NE Phase II Gas Study (Feb 2002) - Transient analysis By winter of 2004/05, 2,800 MW to 3,900 MW of unserved generation Dual & liquid fuel generation is required to makeup winter unserved shortfalls

7. Energy security in the Boston sub-area is critically dependent on LNG from Distrigas A postulated loss of LNG from Distrigas during the winter heating season would impair regional energy security, both gas & electric No other power plant in U.S. or Canada is currently dependent on LNG for ALL of its fuel supply - however - heavily utilized in Pacific rim Existing pipeline capacity on Tennessee and Algonquin during winter cannot replace LNG deliveries to Mystic 8 & 9 Mystic 8 & 9 capacity becomes increasingly important as older fossil steam units are pressured to retire within the Boston sub-area The proposed pipeline expansion projects, Deer Island Lateral and Everett Extension, would provide two important functions: Another pathway to Mystic Station to provide a secondary fuel source An alternative send-out path to reach Algonquin system via Hubline

Fuel Diversity Analysis
RTEP03 Fuel Diversity Analysis TEAC17 Presentation July 10, 2003 Peter Wong ISO-NE Power Supply & Reliability

The objective of this analysis is to investigate the impact on system resource adequacy due to different potential fuel shortages, covering 2003 through 2012, assuming: Fixed NEPOOL generation capacity mix Currently known transmission constraints No change in bid strategy or behavior.

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.

Two types of impact on the NEPOOL bulk power system were conducted for this analysis, assuming shortages of nuclear, coal, oil, natural gas and hydro: Impact on NEPOOL LOLE Impact on NEPOOL energy needs

System load, generating capacity and static transmission interface limit assumptions are consistent with RTEP03 MARS (reliability) and IREMM (congestion) simulations. These assumptions are summarized in the following slides for reference.

2003 New England Annual Peak Load Forecast 50 and 10 Percent Chance of Exceeding (MW)
Year Summer Peak Load (MW) 2003 25,120 / 26,630 2004 25,690 / 27,260 2005 25,996 / 27,590 2006 26,292 / 27,910 2007 26,622 / 28,260 2008 26,991 / 28,650 2009 27,392 / 29,080 2010 27,818 / 29,530 2011 28,265 / 30,000 2012 28,709 / 30470 Year Winter Peak Load (MW) 2003/04 22,010 / 22,900 2004/05 22,296 / 23,200 2005/06 22,575 / 23,490 2006/07 22,873 / 23,800 2007/08 23,207 / 24,140 2008/09 23,571 / 24,520 2009/10 23,941 / 24,910 2010/11 24,347 / 25,330 2011/12 24,773 / 25,770 2012/13 25,166 / 26,170

2003 RTEP Sub-Area Peak Load Forecast 50 Percent Chance of Exceeding (MW)

Installed Capacity Forecast (Summer)
The base case annual installed capacity for the period 2003 through 2012 is 31,093 MW (summer rating). This amount reflects the assumption that 3,452 MW of new units will be installed by June 1, 2003. It also reflects that 564 MW of unit attritions assumed as of June 1, 2003.

Unit Addition Assumptions
Summer Rating (MW) AES Granite Ridge (NH) Milford Units (SWCT) 490 Mystic Units (BOSTON) ,414 Fore River (SEMA) English Station (CT) Great Northern Hydro (BHE) 100 Total ,452 All assumed in service by June 1, 2003

Unit Attrition Assumptions
Summer Rating (MW) Devon 7 and 8 (SWCT) New Boston 1 (BOSTON) Total All assumed retired on June 1, 2003

Generating Unit Availability
Generator unit availabilities are based on 5-year average of historical data ( ). 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.

For new CC units, unit immaturity is assumed for first 3 years of operation. After this period, TUA is used. 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.

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 Assumptions (Percent)

NEPOOL OP 4 Modeled Load and capacity relief associated with NEPOOL OP 4 are modeled in reliability simulations. The assumed relief are based on best available data as of March 2003. Details of the Actions of OP 4 can be found on ISO web site in the Rules and Procedures Section.

Interruptible and Dispatchable Loads Minimum Operating Reserve
New England OP-4 Load Relief Assumptions Interruptible and Dispatchable Loads OP-4 Action 9 OP-4 Action 10 5% Voltage Reduction Minimum Operating Reserve Total OP-4 Load Relief June-September 244 MW 40 MW 5 MW 327 MW - 200 MW 416 MW October - May 224 MW 286 MW 355 MW

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.

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 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

Transmission Interface Limits
Transmission limits assumed for RTEP03 reflect operating limits definitions, consistent with SMD Represent potential limiting areas of the NEPOOL transmission system that may become constrained under a variety of system conditions. The most limiting transmission facility and critical contingency, which limit the interface transfer, may change, depending on unit dispatch, load level and load distribution. For modeling purposes these interface limits are shown as static. These interface limits have been defined to gauge the amount of power which can be transferred between or through various areas before a limitation is reached.

Transmission Interface Transfer Limits
Changes from 2002 RTEP Study Highgate Import – 225 MW to 210 MW Boston Import – 3,500 MW to 3,600 MW NY to NE – 1,400 MW to 1,550 MW (summer) and 1,700 MW to 975 MW (winter) SEMA Export – 1,400 MW to 2,300 MW SEMA/RI – 2,200 to 3,000 MW East-West – 2,100 MW to 2,400 MW CT import – 2,500 MW to 2,200 MW SWCT Import – 1,850 MW to 2,000 MW in 2003 CSC Co. Cross Sound Cable Import – 330 MW to 300 MW

Transmission Interface Transfer Limit Assumptions (Static Limits Used for Modeling)
Interfaces Interface Limit Assumptions (MW) Basic Information for Interface Limits Explanation Relevant Study or Descriptive Information Availability NB-NE 700 Stability NB-NE Tie Study Public – Contact ISO-NE HQ-NE (Highgate) 210 HVDC Design Limit and Voltage N/A NY – NE (w/o Cross Sound Cable) Summer – 1,550 Winter – 975 Thermal NYISO S 2002 Operating Study NYISO Operating Study Public – NYISO website HQ-NE (Phase II) 1500 External Voltage Constraints (PJM & NY) Historical operating limit

Interfaces Interface Limit Assumptions (MW) Basic Information for Interface Limits Explanation Relevant Study or Descriptive Information Availability Orrington South Export 1,050 Thermal (Summer) Bucksport System Impact Study (SIS) Public – Contact Central Maine Power Surowiec South 1,150 Stability 2000 Maine Operating Study Confidential – Strategic Information Maine – New Hampshire 1,400 North - South 2,700 MW Thermal (summer) Typical Operating Study Results Confidential – Strategic Information

Interfaces Interface Limit Assumptions (MW) Basic Information for Interface Limits Explanation Relevant Study or Descriptive Information Availability Boston Import 3,600 Thermal (Summer) 2000 NEMA/Boston Study Public – ISO-NE website – RC documents Section SE Mass Export 2,300 Stability ISO-NE Studies To be determined SE Mass/RI Export East – West Connecticut Import 3,000 2,400 2,200 Simultaneous Stability / Thermal Voltage

Interfaces Interface Limit Assumptions (MW) Basic Information for Interface Limits Explanation Relevant Study or Descriptive Information Availability Connecticut Export 2,030 Thermal (Summer) Export Limit – NU Haddam Neck SIS Confidential – Strategic Information Southwest Connecticut Import 2003: 2,000 2005: 2,600 2008: 3,400 Voltage Thermal ISO-NE Studies To be determined Norwalk – Stamford 2003: 1,100 2005: 1,300 2008: 1,500 Typical Operating Study Result

The following 5 slides show the generating units that are served by the 5 major gas pipe lines in New England.

Note: Devon 8 and 9 are assumed to be retired on June 1, 2003 in the RTEP03 studies.

Loss of generation by fuel type scenarios (one fuel type at a time): Nuclear – 100% Natural Gas Loss by 20% increments Loss by pipeline (5) Loss of LNG facilities(Mystic 8 & 9) Coal – 100% Oil Hydro – 100 % (including pumped storage)

NEPOOL Generating Capacity Mix by Fuel Type

Capacity Mix by Fuel Type – Maine 2003 - 2012
Percent may not add exactly to 100 due to rounding

Capacity Mix by Fuel Type- Mass. 2003 - 2012

Capacity Mix by Fuel Type - RI 2003 - 2012

Capacity Mix by Fuel Type – Conn. 2003 -2012

Capacity Mix by Fuel Type – Vermont 2003 -2012

Results – System Reliability
Results are based on modeling assumptions and limitations and can be misleading if taken out of context. Failure to meet LOLE criteria suggests major problems for the RTEP areas and NEPOOL system, but LOLE analysis doesn’t capture all of the problems within and between NEPOOL sub areas.

System Reliability Loss of All Gas Units

System Reliability Loss of All Oil Units

System Reliability Loss of All Nuclear Units

System Reliability Loss of All Coal Units

System Reliability Loss of All Hydro Units

Loss of 20% of the Gas Generating Capability

Loss of 20% of the Oil Generating Capability

Loss of Mystic Block 8 & 9 Results are based on modeling assumptions and limitations and can be misleading if taken out of context. Failure to meet LOLE criteria suggests major problems for the RTEP areas and NEPOOL system, but LOLE analysis doesn’t capture all of the problems within and between NEPOOL sub areas.

Fuel Diversity Study - LOLE
The top three sub-areas most impacted by the loss of: Gas generation - CNEMA, BOSTON and SWCT Oil generation - NOR, CT and BOSTON Nuclear generation - NOR, CT and SWCT Coal generation - NOR, SWCT and BOSTON

Impact on NEPOOL Energy due to assumed generating capability shortage relating to fuel

NEPOOL Annual Un-served Energy ( ) - GWh Results are based on modeling assumptions and limitations and can be misleading if taken out of context. Failure to meet LOLE criteria suggests major problems for the RTEP areas and NEPOOL system, but LOLE analysis doesn’t capture all of the problems within and between NEPOOL sub areas.

Monthly NEPOOL Un-served Energy Due to 100% Fuel Supply Shortage (2004) - GWH Results are based on modeling assumptions and limitations and can be misleading if taken out of context. Failure to meet LOLE criteria suggests major problems for the RTEP areas and NEPOOL system, but LOLE analysis doesn’t capture all of the problems within and between NEPOOL sub areas.

NEPOOL Un-served Energy Due to Gas Supply Shortage - GWH Results are based on modeling assumptions and limitations and can be misleading if taken out of context. Failure to meet LOLE criteria suggests major problems for the RTEP areas and NEPOOL system, but LOLE analysis doesn’t capture all of the problems within and between NEPOOL sub areas.

Monthly NEPOOL Un-served Energy Due to Gas Supply Shortage – GWH (2004) Results are based on modeling assumptions and limitations and can be misleading if taken out of context. Failure to meet LOLE criteria suggests major problems for the RTEP areas and NEPOOL system, but LOLE analysis doesn’t capture all of the problems within and between NEPOOL sub areas.

NEPOOL Un-served Energy Due to Oil Supply Shortage -GWH Results are based on modeling assumptions and limitations and can be misleading if taken out of context. Failure to meet LOLE criteria suggests major problems for the RTEP areas and NEPOOL system, but LOLE analysis doesn’t capture all of the problems within and between NEPOOL sub areas.

Monthly NEPOOL Un-served Energy Due to Oil Supply Shortage GWH (2004) Results are based on modeling assumptions and limitations and can be misleading if taken out of context. Failure to meet LOLE criteria suggests major problems for the RTEP areas and NEPOOL system, but LOLE analysis doesn’t capture all of the problems within and between NEPOOL sub areas.

NEPOOL Energy Deficiency Due to Pipeline Failure

NEPOOL Un-served Energy Due to Pipeline Failures - GWH Results are based on modeling assumptions and limitations and can be misleading if taken out of context. Failure to meet LOLE criteria suggests major problems for the RTEP areas and NEPOOL system, but LOLE analysis doesn’t capture all of the problems within and between NEPOOL sub areas.

NEPOOL Un-served Energy

Monthly NEPOOL Un-served Energy Due to Pipeline Failure GWH (2004) Results are based on modeling assumptions and limitations and can be misleading if taken out of context. Failure to meet LOLE criteria suggests major problems for the RTEP areas and NEPOOL system, but LOLE analysis doesn’t capture all of the problems within and between NEPOOL sub areas.

Fuel Diversity Analysis - Observations
Handout at meeting (The following 5 slides were handed out at the meeting)

Fuel Diversity Study - Observations
Gas fired generating units in SWCT are served by the Iroquois interstate pipeline. The loss of this pipeline would present the most severe impact on NEPOOL system LOLE as compared with the loss of other pipelines. Algonquin serves the most gas fired generating units as compared to other interstate pipelines. The loss of this pipeline would result in the second most severe impact on NEPOOL system reliability. The loss of the M&N and Portland pipelines is not expected to have an adverse impact on NEPOOL system reliability.

Loss of all Gas-fired units results in a significant amount of LOLE in New England. Loss of Oil-fired units is the second most critical loss in terms of LOLE. The loss of nuclear units has the greatest effect on the sub-areas within CT because of its dependence on nuclear generation. Nuclear capacity accounts for approximately 30 % of the capacity in CT. Loss of Coal and Hydro powered units has a small effect on LOLE compared to the Base Case.

Loss of LNG in New England (Mystic 8 & 9),effects NEPOOL LOLE but only through the Boston sub-area. Other areas are marginally effected.

ENS is the greatest with the loss of gas-fired capacity followed by oil. This is the same observation in the LOLE analysis. On a monthly basis in 2004, the loss of 100% of all gas shows the greatest effect on ENS. The large drop of ENS from May to June is due to the maintenance scheduling of the model. With 0% of the oil-fired generation available ENS seems volatile. The drop in ENS is due to the in-service of new capacity in Jun-03 while the remaining annual volatilities are a product of the new unit immaturity rate assumptions.

In terms of ENS, the loss of the gas-fired generation supplied by the Algonquin creates the largest problem in the later years of the study period whereas the loss of the Iroquois pipeline creates the largest problem in the earlier years. This is due to the amount of generation supplied by the Algonquin pipeline and the critical area that the Iroquois pipeline serves. The loss of the M&N or Portland pipelines (not simultaneously) will not result in an adverse impact in terms of ENS.

Air Emissions Analysis
A Presentation to the Transmission Expansion Advisory Committee Scott Hodgdon July 10, 2003

Objective Quantify the amount of aggregate generating unit air emissions (SO2, NOX, and CO2) in select scenarios investigated within RTEP03 Transmission interface limit scenarios Fuel price scenarios Sub-area incremental/decremental load scenarios Unit generation results obtained from IREMM results

Emission Rate Assumptions
Units of lbs/MWh Obtained from various sources US EPA (Scorecard and Egrid2002) Henwood Energy Services Inc. NERC Database (Licensed by ISO-NE) Similar type units MA and CT State regulations/legislations modeled State Renewable Portfolio Standards not taken into consideration.

Connecticut State Legislations/Regulation 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) The value of X can be found in each stations Emission Control Plans

Scenarios Base assumptions (fuel cost based generator bids)
Base with 20% higher bids in CT areas and Boston Base with Oil, Gas, and both fuel costs increased 25% Select scenarios currently on the bill for RTEP03 will be used to calculate the total annual emissions. Scenarios with meaning will be used

Scenarios Unconstrained case
Base with increases in various transmission limits Boston SWCT, NOR Import East-West Incremental and decremental load cases using on Base Case Assumptions Select scenarios currently on the bill for RTEP03 will be used to calculate the total annual emissions. Scenarios with meaning will be used

Transmission Assumptions
Case Transmission Assumptions (MW) Yellow highlights changes from Base Select scenarios currently on the bill for RTEP03 will be used to calculate the total annual emissions. Scenarios with meaning will be used

Results – 10 year Totals – SO2
Higher Gas Price Total Emissions presented by year by area/state – (best reflects the average annual emission rates) Percent and total deviations from the reference case for each case Under incremental/decremental load cases, total emissions under the “decremental load” cases can be shown using various assumptions for how the “load decrement” was met. I.e. micro-turbines, fuel cells, diesels.

Results – 10 Year Totals – CO2

Results – 10 Year Totals – NOX

Results – 10 Year Totals Higher gas prices lead to a significant increase in NEPOOL air emissions of SO2, NOX, and CO2 when compared to Base Case. Higher oil prices lead to less NEPOOL air emissions 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 – SO2
Total Emissions presented by year by area/state – (best reflects the average annual emission rates) Percent and total deviations from the reference case for each case Under incremental/decremental load cases, total emissions under the “decremental load” cases can be shown using various assumptions for how the “load decrement” was met. I.e. micro-turbines, fuel cells, diesels.

Results – Annual Totals – CO2

Results – Annual Totals – NOX

Results – Annual Totals
2004 has bump in all air emissions due to fuel price assumptions for that year – Natural Gas is assumed to be around 20% higher than oil for 2004. 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. Total Emissions presented by year by area/state – (best reflects the average annual emission rates) Percent and total deviations from the reference case for each case Under incremental/decremental load cases, total emissions under the “decremental load” cases can be shown using various assumptions for how the “load decrement” was met. I.e. micro-turbines, fuel cells, diesels.

Results – Inc/Dec Loads – SO2
NEPOOL Aggregate SO2 Emissions (kTons) Under Incremental/Decremental Loads 132 133 134 135 136 137 138 -500 -400 -300 -200 -100 100 200 300 400 500 Load Change by Sub-Area (MW) SO2 kTons BHE BOS CMA CT ME NH NOR RI SEM SME SWC VT Total Emissions presented by year by area/state – (best reflects the average annual emission rates) Percent and total deviations from the reference case for each case Under incremental/decremental load cases, total emissions under the “decremental load” cases can be shown using various assumptions for how the “load decrement” was met. I.e. micro-turbines, fuel cells, diesels. WEM

Results – Inc/Dec Loads – CO2
NEPOOL Aggregate CO2 Emissions (kTons) Under Incremental/Decremental Loads 52,000 53,000 54,000 55,000 56,000 57,000 -500 -400 -300 -200 -100 100 200 300 400 500 Load Change by Sub-Area (MW) CO2 kTons BHE BOS CMA CT ME NH NOR RI SEM SME SWC VT WEM Total Emissions presented by year by area/state – (best reflects the average annual emission rates) Percent and total deviations from the reference case for each case Under incremental/decremental load cases, total emissions under the “decremental load” cases can be shown using various assumptions for how the “load decrement” was met. I.e. micro-turbines, fuel cells, diesels.

Results – Inc/Dec Loads – NOX
NEPOOL Aggregate NOX Emissions (kTons) Under Incremental/Decremental Loads 47.0 47.5 48.0 48.5 49.0 49.5 -500 -400 -300 -200 -100 100 200 300 400 500 Load Change by Sub-Area (MW) NOx kTons BHE BOS CMA CT ME NH NOR RI SEM SME SWC VT WEM Total Emissions presented by year by area/state – (best reflects the average annual emission rates) Percent and total deviations from the reference case for each case Under incremental/decremental load cases, total emissions under the “decremental load” cases can be shown using various assumptions for how the “load decrement” was met. I.e. micro-turbines, fuel cells, diesels.

Results – Inc/Dec Loads
SWCT load changes have the greatest effect on total NEPOOL air emissions Oil and Coal Fired Units BHE load changes have the least effect of total NEPOOL air emissions Hydro Units Total Emissions presented by year by area/state – (best reflects the average annual emission rates) Percent and total deviations from the reference case for each case Under incremental/decremental load cases, total emissions under the “decremental load” cases can be shown using various assumptions for how the “load decrement” was met. I.e. micro-turbines, fuel cells, diesels.

Results – Decremental Loads From DR
What happens to emissions if the load decrement in each area is from a certain type of Distributed Resources (DR)? Total load decrease multiplied by assumed DR air emission rates and resultant emission added to total NEPOOL emissions. Used Boston Area as baseline due to low variance of emissions from the load changes in different areas Total Emissions presented by year by area/state – (best reflects the average annual emission rates) Percent and total deviations from the reference case for each case Under incremental/decremental load cases, total emissions under the “decremental load” cases can be shown using various assumptions for how the “load decrement” was met. I.e. micro-turbines, fuel cells, diesels.

Distributed Resource Emission Rate Assumptions* Total Emissions presented by year by area/state – (best reflects the average annual emission rates) Percent and total deviations from the reference case for each case Under incremental/decremental load cases, total emissions under the “decremental load” cases can be shown using various assumptions for how the “load decrement” was met. I.e. micro-turbines, fuel cells, diesels. * Source – Model Regulations For the Output of Specified Air Emissions From Smaller-Scale Electric Generation Resources, by The Regulatory Assistance Project

Results – Decremental Loads From DR – SO2 Boston

Results – Decremental Loads From DR – CO2

Results – Decremental Loads From DR – NOX

Pure load reduction (DSM) or Renewable Resources are “cleanest” way to reduce demand. Depending on DR being used, there could be some benefit in terms of total NEPOOL air emissions. Since assumed SO2 for all investigated sources but diesels are nearly zero, marginal effect on SO2 from those various DR types. Total Emissions presented by year by area/state – (best reflects the average annual emission rates) Percent and total deviations from the reference case for each case Under incremental/decremental load cases, total emissions under the “decremental load” cases can be shown using various assumptions for how the “load decrement” was met. I.e. micro-turbines, fuel cells, diesels.

TEAC17 July 10, 2003 Congestion Analysis Wayne Coste, IREMM,Inc.

Presentation Overview
Review of cases investigated Cases investigated and discussed previously Risk sensitivity Monte Carlo based congestion cases Targeted Transmission Assessments Effect of unavailable units Large nuclear Age based unit blocks in Connecticut Maine / New Hampshire export limits

Cases Discussed In Prior TEAC
Reference case Fuel cost based bids Fuel cost bids plus 20% (All CT & BOST) Higher Oil and Gas Oil 25% higher Gas 25% higher Oil and Gas 25% higher More HQ energy based on 2000 MW limit

Cases Discussed In Prior TEAC (cont.)
Transmission Improvements CT import increased by 800 MW CT and E/W increased by 800 MW SWCT Phase I E/W increased by 800 MW and SWCT Phase I CT and E/W increased and SWCT Phase I Boston increased by 800 MW

Comparison of Cases Note: HQ at 2000 MW case revised
Results are based on modeling assumptions and limitations and can be misleading if taken out of context. Note especially that “uplift” and internal transmission constraints within sub-areas are not included.

Sensitivity Risks

Effect of Changes in Sub-Area Loads on NEPOOL
Congestion Costs (2004) Western Side Eastern Side BOST CT BHE, / ME SWCT SME WEMA, / VT NOR SEMA Load Increases in MW on chart could also represent Loss of Resources Results are based on modeling assumptions and limitations and can be misleading if taken out of context.

Effect of Changes in Sub-Area Loads on NEPOOL
Congestion Costs (2004) NOR SWCT BOST WEMA SEMA CT VT Load Increases in MW on chart could also represent Loss of Resources Results are based on modeling assumptions and limitations and can be misleading if taken out of context. Note especially that “uplift” and internal transmission constraints within sub-areas are not included.

Effect of Unit Attrition / Outages in BOST
Results are based on modeling assumptions and limitations and can be misleading if taken out of context. Congestion results are intended to indicate trends for planning purposes and are not accurate market price forecasts. Note especially that “uplift” and internal transmission constraints within sub-areas are not included.

Reference Case: Fuel Cost Based Bids
Note: The slides labeled “Observation” are an integral part of understanding the context of this slide Results are based on modeling assumptions and limitations and can be misleading if taken out of context. Congestion results are intended to indicate trends for planning purposes and are not accurate market price forecasts. Note especially that “uplift” and internal transmission constraints within sub-areas are not included.

Monte Carlo Based Congestion - Base Case
Note: The slides labeled “Observation” are an integral part of understanding the context of this slide Monte Carlo forced outage based congestion tends to be higher than derated forced outage congestion Results are based on modeling assumptions and limitations and can be misleading if taken out of context. Congestion results are intended to indicate trends for planning purposes and are not accurate market price forecasts. Note especially that “uplift” and internal transmission constraints within sub-areas are not included.

Monte Carlo Based Congestion - Connecticut Age Blocks Unavailable; SWCT Phase I, CT, EW and SEMA Upgrades Note: The slides labeled “Observation” are an integral part of understanding the context of this slide Monte Carlo forced outage based congestion tends to be higher than derated forced outage congestion Results are based on modeling assumptions and limitations and can be misleading if taken out of context. Congestion results are intended to indicate trends for planning purposes and are not accurate market price forecasts. Note especially that “uplift” and internal transmission constraints within sub-areas are not included.

Observations of Congestion Cost Trends
Congestion costs increase over time as the system: Becomes more constrained East/West becomes a dominant constraint Exports to New York expected to exacerbate effect CT Import is significant SWCT Import is still most significant constraint Most significant reductions in congestion due to upgrades: East / West CT Import SWCT For changes that are considered here for fuel prices: Change affect costs to LSEs not congestion Minor impact on congestion costs

Targeted Congestion Cases

Targeted Cases More detailed investigation of the effect of improvements on congestion costs There are significant risk factors that are not captured in the “base case” type analysis Consider outage of one or more generation resources Long term outages have been seen in the past and Unexpected long term outages could reoccur in the future Congestion cost risks are skewed toward higher congestion Show market discipline benefits of transmission improvements

Targeted Cases - CT Import
Effect of extended outages of large units Millstone 2 Millstone 3 Millstone 2 and 3 Effect of unavailable fossil units by vintage Aggregate into 4 blocks Consider the unavailability of all four blocks

New England LSE Expense - Millstone Outages

New England Congestion Cost - Millstone Outages

Definition of Vintage Related Blocks
Major fossil units in Connecticut that have been installed since 1954(excluding coal-fired units) Norwalk 1 and 2 are among the oldest A number of older units have already been retired in the past (eg. Middletown 1)

New England LSE Expense - As-Is

New England Congestion Cost - As-Is

New England LSE Expense - CT Phase I

New England Congestion Cost - CT Phase I

New England LSE Expense - SWCT Phase I, CT, E/W and SEMA Upgrade

New England Congestion Cost - SWCT Phase I, CT, E/W and SEMA Upgrade

Targeted Cases - Maine / New Hampshire
Effect of conditionally dependent transmission constraints Modeled for two summer months (July / August) ME/NH interface reduced from 1400 to 950 MW Derate assumed driven by a unit outage Cases Reference case One Connecticut age related block unavailable Two Connecticut age related blocks unavailable Proxy for other conditions

Congestion Savings due to Eliminating Conditionally Dependent Interface Derate: July and August Only for Effect of Price Spikes in Unconstrained Cases Results are based on modeling assumptions and limitations and can be misleading if taken out of context. Congestion results are intended to indicate trends for planning purposes and are not accurate market price forecasts. Note especially that “uplift” and internal transmission constraints within sub-areas are not included.

Congestion Savings from Eliminating Conditionally Dependent Interface Derates: SWCT Phase I, CT, EW and SEMA Upgrades Results are based on modeling assumptions and limitations and can be misleading if taken out of context. Congestion results are intended to indicate trends for planning purposes and are not accurate market price forecasts. Note especially that “uplift” and internal transmission constraints within sub-areas are not included.

Congestion Savings from Eliminating Conditionally Dependent Interface Derate: First Connecticut Age Related Block Unavailable Results are based on modeling assumptions and limitations and can be misleading if taken out of context. Congestion results are intended to indicate trends for planning purposes and are not accurate market price forecasts. Note especially that “uplift” and internal transmission constraints within sub-areas are not included.

Congestion Savings for Eliminating Conditionally Dependent Interface Derate: Two Connecticut Age Related Block Unavailable Results are based on modeling assumptions and limitations and can be misleading if taken out of context. Congestion results are intended to indicate trends for planning purposes and are not accurate market price forecasts. Note especially that “uplift” and internal transmission constraints within sub-areas are not included.

Flow Effect of Eliminating Conditionally Dependent Interface Derate:
SWCT Phase I, CT, EW and SEMA Upgrades: 2008

Targeted Cases - ME/NH Observations
Congestion costs are sensitive to the ME/NH conditionally dependent interface derate Two month unit outages in summer Have been observed Credible contingency with significant impacts Risk factors exist that could magnify congestion Base Case ME/NH exports are generally less constraining than in RTEP01 and RTEP02 Improved SEMA/RI export capability increases availability of energy from new CC units

Inter-Regional Issues
TEAC17 July 10, 2003 Mike Henderson ISO-NE (presented out of agenda order)

Inter-Regional Issues
TO BE EXPANDED TFSS SS38 TFCP CP8 RPF CP10 Inter-ISO Liaison Task Force Data and Information Sharing Studies

Keswick GCX & NE-NB Tie Performance Concerns TEAC17 July 10, 2003 Rich Kowalski ISO-NE

Purpose of Keswick GCX SPS
Protects the 345kV NB-NE tie overload tripping due caused by large load losses within the Maritimes Accomplishes this by using a combination of power flow sensing distance relays and over/under frequency relays such that generation rejection is allowed only if an extremely high export flow is sensed coincident with a high frequency surge

System Performance Transient inter-Area power swings because of a system disturbance in New England can result in: GCX characteristic entry: 550 MW generation trip or HVDC runback in Maritime NB-NE tie line trip: 700 MW source loss to New England plus Maine Independence Station (396 SPS) Potential Northeast region-wide reliability problem Millions of Dollars have been and will continue to be spent all over NE to prevent entering Keswick GCX characteristic for design contingencies Millions of Dollars have also been and will continue to be spent to mitigate source loss for extreme contingencies

System Performance (cont.)
Local contingencies potentially result in adverse inter-Area impacts Necessitates installing redundant circuit breakers, second high-speed protection systems, reducing relay timings, upgrading breakers to have IPT capability, redundant battery supplies, additional control houses, etc. on an ongoing basis Many stations might be classified as Bulk Power Systems (BPS) because of the GCX characteristic entry or NB-NE tie trip (inter-Area impact) necessitating the need for additional expenditures

Criteria Normal Contingency: Extreme Contingency
Entry of the Keswick GCX Characteristic is unacceptable Extreme Contingency Source loss over 1400MW are evaluated on a case by case basis and absolutely unacceptable above 2200MW

Study Objective Find realistic enhancements to New England system to
avoid GCX entry for normal contingency avoid NB-NE tie trip for extreme contingency avoid unnecessary impacts resulting in stations becoming BPS because of GCX entry or NB-NE tie trip

Alternative System Enhancements Being Considered
STATCOM at Chester, Orrington, Maxcys or Maine Yankee Series Compensation on line 396 Thyristor Controlled Series Compensation (TCSC) on line 396 SuperVAR Dynamic Synchronous Condensors

Preliminary Findings Effective enhancements
50% series compensation on line 396 Thyristor Controlled Series Compensation (33% compensation) Limited simulations have shown that TCSC is better than the 50% series compensation

New Hampshire Voltage-Constrained Transfer Limit Improvement Project

Issues New Hampshire 345 and 115kV voltage performance concerns
ME-NH voltage, stability, and thermal performance, transfer limitations Increasingly complex stability interrelationships: ME-NH, N-S, E-W, SEMA/RI, NEMA/Boston

Combination of Projects Result in 600 MW Increase
The addition of a dynamic voltage device at Deerfield S/S could raise Maine-New Hampshire transfer limits MW. Looping the 391 Line into Deerfield S/S would increase limits an additional 75MW. Breaker additions at Buxton S/S to remove stuck breaker contingencies will further improve transfer limits MW.

Summary of Representative Limits
Yarmouth 4 Off Line * Stability limits have not been studied with these enhancements

Benefits to New England
Upgrades will allow the full capabilities of the thermal limits to be utilized Project coordinates well with other system projects North- South projects NEMA / Boston projects Breakers and 391 loop into Deerfield S/S will also increase thermal limits Will also reduce must-run generation on Northern New England corridor during light load periods to control high voltage

Preliminary Study Recommendation for Transmission Reinforcements
Locate a Dynamic Voltage Device rated at 500 MVAR (±150 MVAR dynamic, 350 MVAR Fixed) at Deerfield Substation - ~$25 Million Loop Section 391 in and out of Deerfield Substation with addition of three new breakers - ~$6 Million Add three new breakers at Buxton to eliminate stuck breaker contingencies - ~$5 Million Estimated cost for Reinforcements - ~$36 Million

Local New Hampshire Area Problems to be Studied as Identified by TO

New Rochester Tap – Rochester (G128) 115kV Line (2004): Provides a looped supply to the increasing load in the Rochester area Rebuild 115kV along Scobie – Schiller corridor (2006): Increases capacity to supply future load levels when Schiller is unavailable New Seabrook 345kV substation (future): Replaces obsolete GIS equipment

New South Milford – Monadnock 115kV line (2010): Manchester – Nashua area reinforcement
Upgrade Scobie – Sandy Pond 345kV (2006): Increase N-S transfer capability New Scobie – Tewksbury 345kV line (2010): Increase N-S & Boston Import capabilities New Ashland Tap – Ashland 115kV Line (2005): Provides a looped supply to the increasing load in the Ashland area

Connecticut Operating Reserve Assessment
Presentation to the TEAC Meeting Richard V. Kowalski Manager, Transmission Planning ISO New England July 10, 2003

Operating Reserve Analysis Methodology
Considered most severe of either largest generator or transmission facility (extended outage), in addition to an average amount of capacity out of service Operating reserve deficiency calculated as the area load minus generation resources minus transmission import capability Reference and high demand load forecasts respectively bracket the minimum and maximum capacity deficiencies Summer peak loads forecast for 2003 through 2012

Load Data CT Load : 27.5% of NEPOOL Load

Slide Redacted

Nameplate Generation Data

Key Analysis Factors CT Import Area Outage scenarios tested
2,200 MW Import Capability (All facilities initially in) 1,400 MW Import Capability (Critical facility initially out) Largest generator outage (Millstone 2 or 3): MW 440 MW average generation out-of-service Assumed PUSH unit’s availability at 2/3 of full capacity Load shifting or load shedding not considered to address deficiencies Outage scenarios tested Each and both Millstone units out 300 MW of PUSH units out 700 MW of “40yrs +” units out

PUSH Units “40yrs +” Units

Summary of Results In 2003 All units in: risk of deficiency if high load “40yrs +” units out: 330 MW to 750 MW deficiency One Millstone out: 530 MW to 940 MW deficiency In 2006 Deficiencies ranging from 650 MW to 1250 MW if “40yrs +” units or one Millstone are out

Conclusions Need to support the development and implementation of the alternative reinforcement project considered under the SEMA-RI Export Enhancement Analysis (345 KV line from Millbury to Card) as it will also increase Connecticut Import Capability Need to study for a second transmission reinforcement to address future needs and the possibility of inadequate resource development

TEAC17 July 10, 2003 Rich Kowalski ISO-NE
Salem Harbor, Mystic 4, 5 & 6, and New Boston 1 Reliability Impact Assessment TEAC17 July 10, 2003 Rich Kowalski ISO-NE

DISCLAIMER "As noted by Mr. Kowalski orally during the June 12, 2003 Technical Session, the analysis presented herein is a non-final, preliminary analysis, the conclusions in which are subject to change as ISO-NE continues its analysis. The analysis is built upon other analyses, including load forecasts and various assumptions, only some of which are specified herein. For example, the analysis has used the nameplate capability of the relevant generating units, but that capability can change on a daily basis and recent experience has been that actual capability is less than nameplate. Further, the analysis uses typical transmission capability, but actual transmission capability will vary depending on actual unit dispatch and load. Additionally, the analysis has assumed average outage experience, but of course, actual experience can be better or worse. ISO-NE also notes that there is inherent variability in forecasts of load and other inputs, so that the numbers in this presentation cannot be deemed to be absolute, but rather the analysis is a planning tool. Finally, ISO-NE cautions that this presentation may be misleading if read out of context of explanations provided, statements made, and questions addressed, at the June 12 Technical Conference."

Purpose – Status Report
Salem Harbor, Mystic 4-6 & New Boston 1 Generation plans for retirement submitted as NEPOOL 18.4 applications Mystic 4-6 September 1, 2003 New Boston 1 December 31, 2003 Salem Harbor 1-4 October 1, 2004 ISO-NE, National Grid and NSTAR Transmission Adequacy Assessment of bulk electric system reliability in the North Shore and the Boston Import Area* (and Downtown Boston) for 2003 through 2012 Study of longer term transmission improvements * Boston Import Area includes North Shore (National Grid) and most of Boston Edison and Cambridge Electric

Study Criteria and Methods
Studies in compliance with NERC, NPCC, NEPOOL, and local area criteria consistent with NEPOOL procedures Resource Adequacy LOLE Measure of resource adequacy from a planning perspective Overall indicator of significant area problem Transmission Adequacy Operating Reserve Analysis Measure of adequacy of operating reserve Indication of significant reliability problems due to inadequate generation and transmission capacity. Transmission Reliability Analysis Measure of detailed reliability of service on a bus-by-bus basis using traditional “load flow” methods Indication of significant transmission system problems that could manifest as a real-time security issue

Boston Import Area LOLE Results
Resource Adequacy Analysis using only Boston Area Import constraints Does not consider internal transmission constraints or simultaneous unit operating constraints Failure to meet required LOLE Units Retired of 0.1 days/year for year* Mystic 4, 5, 6 and NB Salem Harbor Plant SH, Mystic 4, 5, 6, and NB * Need to focus on more detailed operating reserve and transmission reliability analysis

NEPOOL Agreement Sections 18.4, 18.5
18.4 – Requires identification of potential adverse impacts resulting from proposed retirements. 18.5 – The Participant must address the identified adverse impacts through: successful FERC filing resulting from good faith negotiation to be completed within 90 days of the 18.4 decision. other means

Operating Reserve Analysis
Operating Reserve Analysis – reserves needed to cover the loss of either the largest unit or worst transmission contingency “Un-served Energy” – Amount of load at risk calculated from load duration curve, existing generation resources and transmission import capability

Operating Reserve Analysis Methodology
Considered most severe of either largest generator or transmission facility (extended outage), in addition to an average amount of capacity out of service Un-served energy calculated as the area load minus generations resources minus transmission import capability integrated over the load duration curve Reference and high demand load forecasts respectively bracket the minimum and maximum capacity deficiencies Summer peak loads forecast for 2003 through 2012 This assessment also considered: The existing system including recent NEMA transmission upgrades

Load Data “Reference” Summer Peak Load Forecast

Load Data “High Case” Summer Peak Load Forecast

Slide Redacted

Nameplate Generation Data

Complicating Factors The transmission system performance of the Boston Import Area, Downtown Boston, the North Shore and New England North-to-South are interdependent This analysis used 600 MW North Shore import; coincident with high Boston Import and high New England North-to-South transfers A reduction of the Boston Import capability of 100 MW would increase the North Shore import capability by 10 MW. North Shore import capability increases with lower load

Complicating Factors Also concerns specific to Boston Import, Downtown Boston, and North Shore Proposed retirement of 3 “Plants” consisting of 8 units with a total nameplate capacity of 1,503 MW Potential short-term North Shore transmission upgrades in addition to Package 2 TBD Potential short-term Downtown Boston & Boston Import transmission upgrades TBD Long-term upgrades TBD

Multiple Area Issues Boston Import Area North Shore Downtown Boston
Total resource needs of the greater Boston Import Area Need reserves for loss of generation & transmission North Shore Sub-area of Boston Import area Local needs to serve load System designed recognizing need for reserves for loss of generation Load growth requires transmission expansion with increased need for reserves for loss of transmission Downtown Boston Need reserves for loss of 115 kV generation (Mystic 9)

Key Analysis Factors Boston Import Area
3,600-3,900 MW Import Capability (All facilities initially in) 2,500 MW Import Capability (Critical facility initially out) Largest generator outage (Mystic 8 or 9) – 700 MW Average generation out-of-service – 280 MW Internal short circuit & thermal constraints Mystic 4, 5, & 6, New Boston 1 and other units

Key Analysis Factors North Shore Area Downtown Boston 115 kV
600 MW Existing Import Capability (All facilities initially in) Largest generator outage varies with retirement scenario Salem Harbor 4 – 431 MW Salem Harbor 3 – 151 MW Average generation out-of-service – MW Downtown Boston 115 kV Largest generator outage (Mystic 9) – 700 MW

Annual Operating Reserve Analysis – Boston Import

Annual Operating Reserve Analysis – North Shore

Transmission Reliability Analysis
Identified thermal and short circuit problems within the Boston Import Area. Downtown Boston 115 kV generation required to ensure secure system.

Current Downtown Boston 115 kV Capacity Requirements
Thermal Constraints Load New Boston Must Run or Mystic 4, 5, 6 Must Run Total 2003 Reference ~200 MW ~225 MW 2003 High ~250 MW ~275 MW Short circuit constraints require Mystic 4, 5, 6 off-line when Mystic 9 on. Therefore, due to start-up time, Mystic 4, 5, 6 are not good reserve for Mystic 9.

Summary of Results without Transmission Improvements, but with Units in Good Repair
Boston Import Area (Alone) Mystic 4-6 or New Boston 1 retirement acceptable Mystic 4-6 and New Boston 1 retirement not acceptable Salem 1-4 retirement not acceptable Salem 1-4 retirement with retirement of Mystic 4-6 or New Boston 1 not acceptable North Shore (Alone) All generation is required at Salem Harbor Downtown Boston 115 kV (Alone) ~ MW of generation required New Boston 1 retirement not acceptable Mystic 4, 5, 6, retirement acceptable (alone)

Conclusions The system performance of the North Shore, Downtown Boston, and Boston Import Areas are closely interdependent. Salem Harbor appears to be needed for both Boston Import Area and for North Shore reliability. May be possible to eliminate North Shore specific requirement for Salem Harbor with some proposed transmission upgrades With Salem Harbor available for service, the Boston Import Area has sufficient capability through 2007.

Conclusions (continued)
New Boston 1 is required for service to Downtown Boston. May be possible to eliminate Downtown 115kV-specific requirement for New Boston 1 with transmission upgrades. Mystic 4, 5, & 6 retirement is potentially acceptable. Margins are thin – A force majeure event could compromise reliability of service.

Measures to Address Adverse Impacts
North Shore and Boston Import Area transmission enhancements New 345 kV transmission across NEMA-Boston & Boston Import interfaces New transmission within Boston Import Area, including North Shore Integrated solution to address regional needs

Measures to Address Adverse Impacts (continued)
Interim Alternatives for Consideration Boston Import Area and/or North Shore measures Retain some/all Salem Harbor generation Replacement generation (“base-load” and reserves) Pre & Post contingency Load Shedding Boston Import Area measures Connect Mystic 4-6 to Mystic 345 kV (relieve short circuit concerns) Retain New Boston 1 System modifications to allow temporary Dewar St. load shift to SEMA Add Phase Angle Regulator and close Dewar St. to N. Quincy 115 kV Additional short term North Shore transmission modifications TBD

Locational ICAP Methodology
TEAC17 July 10, 2003 Wayne Coste, IREMM, Inc.

LOLE Reliability Index
Loss of Load Expectation (LOLE) Has wide acceptance in electric power industry LOLE index of 0.1 days per year accepted as threshold for generation adequacy Index is calculated as “Expectation” LOLE is cumulative daily probability of insufficient resources to meet customer loads Transmission only included in inter-area reliability studies

Reliability Risk Measurements
Single bus resource adequacy assessment Measures generation adequacy; and Load response program (LRP) adequacy Constrained Multi-Area assessment. Includes locational component w/o additional T&D risk Composite reliability assessment Generation and LRP adequacy risks plus Transmission and distribution risks “Delivered-to-the-customer-terminal” reliability

Applicability of LOLE Index
LOLE Index (ISO-NE, NYISO and PJM): IS a measure of resource adequacy Can be applied to many interconnected areas IS NOT a composite reliability assessment Criterion is met when regions are inter-connected and LOLE less than, or equal to, 0.1 days/year

Inter-Regional Constraints
Not Generally Constrained Imports or Exports can Dominate Inter-regional constraints leave exporting areas with low LOLE and importing areas with roughly equivalent indices. For minimum ICAP in both B and C (ie. maximum efficiency), both have LOLE and interface is supportive of emergency flows because it is not constraining. Single contingency interface rating (ie. N-1) Determine the amount of capacity in each region so that both (all) areas meet reliability standard. B 0.099 C 0.100 Frequently Export Constrained Frequently Export Constrained A 0.02

Sub-Area LOLE Risk Extension of 0.1 days/year criterion to sub- areas without additional risk factors If resource adequacy is the issue, LOLE index would be uniform across areas Assumption underlying single bus model No recognition of additional risks If resource adequacy LOLE is not uniform across sub-areas Certain customers would be targeted for blackouts while other New England customers won’t be interrupted Interruption guided by ISO / satellite OP4 & OP7 needs

Intra-Area Constraints
Within New England there are many sub-areas. For all areas to see the same resource adequacy risk -- the supply resources and transmission must be balanced. Intra-area locational balance is an extension of the accepted NPCC inter-regional transmission limit framework. Internal interfaces are rated for single contingency (i.e.. N-1) and do not add to risk levels. SME ME BHE SEMA RI WEMA CMAN NH BOST CT SWCT NOR VT

Resource Adjustment Methodology
Once the system is brought to NEPOOL reliability criterion: 1. Add/remove MW from sub-area 2. For Add/remove - Assume X MW change - Other areas reduced by X MW - Reduce according to peak load 3. Identify “Critical Points” - LOLE increases with less MW - LOLE decreases with more MW 0.100 -B MW 0.100 -C MW 0.100 -A MW 0.100 -E MW 0.100 -D MW 0.100 X MW Virtually Unconstrained Net MW adjustment is zero: 0 = X -A -B -C -D -E

Effect of Changing Capacity / Load Ratios ‘Import’ Constrained Area
Effect of Firm Load Shift on LOLE Import Constrained Area 2004 Less Capacity Higher LOLE Lower Capacity / Load Ratio More Capacity No Impact on LOLE Higher Capacity / Load Ratio LOLE (Days Per Year) 0.2 0.4 0.6 0.8 1 1.2 Ratio of Area Capacity / Area Peak 2004 Existing Ratio

Effect of Changing Capacity / Load Ratios ‘Export’ Constrained Area
Effect of Firm Load Shift on LOLE Export Constrained Area Less Capacity No Impact on LOLE Lower Capacity / Load Ratio More Capacity Reduces LOLE Higher Capacity / Load Ratio LOLE (Days Per Year) 0.5 1 1.5 2 Ratio of Area Capacity / Area Peak 2004 Existing Ratio

RTEP03 Peak Load and Installed Capacity MW by Sub-Area – 2003
(Peak Loads – 50/50 F/C) NB-NE - 700 Highgate - 210 HQ Phase II NB VT Load MW Orrington South – 1050 Surowiec South ME-NH – 1400 S-ME ME BHE Load MW Load MW NH Load MW Load MW Boston – 3600 East-West – 2400 BOSTON North-South – 2700 Load MW NY-NE – 1550 w/o Cross Sound Cable W-MA CMA/NEMA Load MW Load MW NY SEMA/RI – 3000 SEMA CT RI Load MW CSC -300 Load MW Load MW South West CT – 2000 SEMA – 2300 KEY: NOR Connecticut Import– 2200 RTEP Load Capacity SWCT Regional Transmission Expansion Plan Sub-area Load MW Load MW Upgraded this year Priority Studies Required Norwalk-Stamford – 1100 Other Studies Required

Effect of Adjusting Capacity in BOST
Preliminary Indications Effect of Firm Load Shift on LOLE BOST 2003 0.1 Days / Year Criterion Sub-Area LOLE Maximum Before Locked-in Minimum Before Import Constrained 2003 Existing Ratio LOLE (Days Per Year) 1000 2000 3000 4000 5000 6000 7000 8000 Existing+Adjustment Capacity in Sub-Area

Effect of Adjusting Capacity in SWCT
Preliminary Indications Effect of Firm Load Shift on LOLE SWCT 2003 0.1 Days / Year Criterion Sub-Area LOLE Maximum Before Locked-in Minimum Before Import Constrained 2003 Existing Ratio LOLE (Days Per Year) 1000 2000 3000 4000 Existing+Adjustment Capacity in Sub-Area

Effect of Adjusting Capacity in NOR
Preliminary Indications Effect of Firm Load Shift on LOLE NOR 2003 0.1 Days / Year Criterion Sub-Area LOLE Maximum Before Locked-in Minimum Before Import Constrained 2003 Existing Ratio Driven by NOR Import LOLE (Days Per Year) Driven by SWCT Import 200 400 600 800 1000 1200 1400 1600 Existing+Adjustment Capacity in Sub-Area

Effect of Adjusting Capacity in N-CT
Preliminary Indications Effect of Firm Load Shift on LOLE CT 2003 0.1 Days / Year Criterion Sub-Area LOLE Maximum Before Locked-in Minimum Before Import Constrained 2003 Existing Ratio LOLE (Days Per Year) 1000 2000 3000 4000 5000 6000 Existing+Adjustment Capacity in Sub-Area

Possible Solutions PJM favors transmission solutions
Uses sub-area import and export criteria Import Capability Emergency Transfer Objective (CETO) criteria of 0.04 days/year Export limited areas trigger planning process NYISO uses Locational Capacity approach Import constrained areas have Locational ICAP Certain transmission eligible for “ICAP” if bundled with generation ISO-NE is pursuing a Locational Capacity approach

Available Solutions Locational ICAP requires minimum amount of local capacity for reliability Increases in transmission capability can reduce the minimum local capacity requirement Non-discriminatory solutions Transmission solution LSEs can foster LRP resources Generation solutions

RTEP Sub-Area Based Reqm’ts
All Existing and New Resources (RTEP03) Available Preliminary Additive Transmission Import Capability From all Areas May Not be Simultaneously Feasible Note: Existing Must Be Greater Than Required

Sub-Area Largest Unit

Sub-Area w/o Largest Unit
Preliminary Additive Transmission Import Capability From all Areas May Not be Simultaneously Feasible Notes: Existing without Largest Unit must be greater than required Insufficient means short without resource attrition risk Vulnerable means short with resource attrition risk

Sub-Area PUSH Units

Sub-Area w/o PUSH Units
Preliminary Additive Transmission Import Capability From all Areas May Not be Simultaneously Feasible Notes: Existing without PUSH Unit must be greater than required Insufficient means short without resource attrition risk Vulnerable means short with resource attrition risk

Next Steps Continue finalizing and communicating to participants
Await NEPOOL Power Supply Planning Committee comments Presentation given May 30th on technical issues Technical approach perceived to be credible by PSPC Comments due by approximately June 13th Development of results for changes in transmission constraint values Obtain comments from your Committee Nesting of Sub-areas Work with Amr Ibrahim to develop a web-based “FAQ” Communicate responses to participants Facilitate understanding of approach and basis for further analysis UCAP translation Extend analysis to include treatment of export constrained areas

TEAC17 Thursday, July 10, 2003 Radisson Hotel

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