NEPOOL Objective Capability (Installed Capacity Requirement) For Power Year 2005/2006

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NEPOOL Objective Capability (Installed Capacity
Requirement)For Power Year 2005/2006

• Presentation to the
• Joint ISO PAC/NEPOOL RC Meeting
• February 2, 2005
• Wyndham Hotel, Westborough MA

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Background

• NEPOOL Objective Capability (OC) is the amount of
  installed capacity that NE needs to meet the
  NEPOOL resource planning reliability criterion of
  1 day in 10 years disconnection of
  non-interruptible customers. This criterion takes
  into account
• Possible levels of peak loads due to weather
  variations,
• Impact of assumed generating unit performance,
  and
• Possible load and capacity relief obtainable
  through the use ofISO-NE Operating Procedure no.
  4 Action During a Capacity Deficiency.

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Background (Contd)

• OC is established by NEPOOL on an annual basis
  one year at a time.
• Power Supply Planning Committee reviews
  assumptions and develop OC scenario(s) for
  Reliability Committee (RC) consideration.
• RC reviews the OC scenario(s) and votes a
  recommendation(s) for Participants Committee
  approval.

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Background (Contd)

• OC is calculated using the single area
  Westinghouse/ABB Capacity Model Program. Single
  area refers to the assumption that there is
  adequate transmission to deliver capacity where
  and when is needed. Simply said, all loads and
  generators are assumed to be connected to a
  single electric bus.

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Background (Contd)

• The Capacity Model uses probabilistic calculation
  that simulates the availability of system
  resources (taking into account each generating
  units assumed forced outages and maintenance
  requirements) to meet the expected load (taking
  into account possible variations due to weather).
  This calculation is often referred to as the
  Loss of Load Expectation (LOLE) calculation.

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• Assumptions
• For 2005/06 OC Calculations

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Assumptions

• Loads
• Capacity
• Existing
• Additions
• Attrition
• Purchases and Sales
• Daily Cycle Hydro Ratings
• ICAP Capable Load Response Program Assets
• SWCT RFP

• Unit Availability
• Tie Benefits
• Other OP-4 Load Relief

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Loads

• Based on CELT 2005 forecast
• Weekly distributions represented with
• Expected value (mean)
• Standard deviation
• Skewness
• Based on short-run seasonal peak load forecast
• Summer peak 26,355 MW
• Winter peak 22,830 MW

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Capacity

• Existing Capacity
• Based on 2005 CELT Data
• Assets within January 2005 Seasonal Claimed
  Capability (SCC) Report
• Summer Rating August 2004 SCC Report
• Winter Rating January 2005 SCC Report
• Units categorized as EMS SO units included
• Energy Management System 30,516 MW (S) 32,878
  MW (W)
• Settlement Only resources 238 MW (S) 313 MW
  (W)

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Capacity

• Capacity Additions
• Ridgewood Generation (8.4 MW)
• Kendall Steam 3 Reactivation (25 MW)
• Kendall CT Reactivation (158 MW)
• Capacity Attrition
• No attrition assumed

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Capacity

• Purchases and Sales
• Purchases and Sales as reported in 2004 CELT
  Report (453 MW)
• Daily Cycle Hydro Ratings
• 50 Percentile value of daily flows assumed with
  adjustment (59 MW in July) to OC.

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Load Response Assumptions

• ICAP Capable Load Response Program
• All capacity listed as of January 1, 2005 as
  ready to respond enrolled in
• Day-Ahead Demand Response Program
• Real-Time Demand Response Program
• Real-Time Profiled Response Program
• Assets grouped by Program and Area
• Assets assumed to have performance factors based
  on August 20, 2004 audit results and NERC Class
  Average EFORd values for known emergency
  generation.

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Assumed MW from Load Response Program
EFOR values based on Aug. 20, 2004 audit results
and NERC Class average data
Program Load Zone MW Assumed in 05/06 OC Calculations MW Assumed in 05/06 OC Calculations Assumed EFOR () Assumed EFOR ()
RT 2-hour Demand Response ME 1.0 30.0
  NEMA 1.5 99.0
  WCMA 9.0 84.0
RT 30 Minute Demand Response CT 218.0 3.9
NEMA 3.0 37.0
 Profiled Response ME 76.0 100.0
  NEMA 1.4 7.45
VT 5.9 100.0
Total Total 315.8

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Emergency Resources

• SWCT RFP
• Contracted SWCT RFP resources not currently
  enrolled in Real-Time Demand Response included
• 218 MW total contracted for summer 2005

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• PSPC recommended using EFORd instead of EFOR to
  be consistent with EFORds application in the
  ICAP market and the UCAP rating for generating
  units.

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EFORd Equation
Where
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• EFORd - Equivalent Demand Forced Outage Rate
• ff - full f-factor
• fp - partial f-factor
• FOH - Full Forced Outage Hours
• EFOH - Equivalent Full Forced Outage Hours Sum
  of all hours a unit was involved in an outage
  expressed as equivalent hours of full forced
  outage at its maximum net dependable capability
• SH - Service Hours The time a unit is
  electrically connected to the system - Sum of all
  Unit Service Hours.
• AH - Available Hours The time a unit is capable
  of producing energy, regardless of its capacity
  level -- Sum of all Service Hours Reserve
  Shutdown Hours Pumping Hours Synchronous
  Condensing Hours
• RSH - Reserve Shutdown Hours The time a unit is
  available for service but not dispatched due to
  economic or other reasons

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Equiv. Forced Outage Rate Demand (EFORd)

• Interpretation
• The probability that a unit will not meet
  itsdemand periods for generating requirements.
• Best measure of reliability for all loading
  types(base, cycling, peaking, etc.)
• Best measure of reliability for all unit
  types(fossil, nuclear, gas turbines, diesels,
  etc.)
• For demand period measures and not for thefull
  24-hour clock.

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Unit Availability Assumption

• 5-year average EFORd modeled
• Forced Outage Rates (EFORd) determined using
  combination of NERC Class Average EFORd data and
  available New England GADs data.
• NERC Class Average used Jan00 Feb03
• Calculated EFORd using GADs used Mar03 Dec 04
• Since Dec 04 data is not yet available,Dec 03
  data is used for Dec 04.

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Unit Availability

• New England Nuclear units performance not
  correctly represented by NERC Class Average EFORd
• For Nuclear units, used ISO-NE calculated Jan00
  through Feb03 EFOR and Mar03 through Dec04
  EFORd.
• Since Dec 04 data is not yet available,Dec 03
  data is used for Dec 04.

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Results of 60-Month Average
Unit Category Summer MW of System 05/06 Assumed WEFORd ()
Fossil 10,179 32.9 6.71
CC 11,040 35.7 6.03
Diesel 121 0.4 5.56
Jet 1,873 6.1 7.09
Nuclear 4,387 14.2 1.35
Hydro (Includes Pumped Storage) 3,340 10.8 3.80
Total System 30,940 100 5.41
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Tie Reliability Benefits

• Tie Reliability Benefits from Hydro-Quebec, New
  Brunswick, and New York are modeled in the
  Westinghouse Capacity Model as Resources
• PSPC suggested two sets of tie benefits
  assumptions
• 1,400 MW (summer values including HQICC)
• 2,000 MW (summer values including HQICC)

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Tie Reliability Benefits - HQICC

• Hydro-Quebec Interconnection Capability Credits
  for 2005/06 are determined based on load and
  capacity data submitted to ISO-NE by Hydro-Quebec
  Distribution and Hydro-Quebec Production.
• The monthly HQICC values recommendedby ISO-NE
  are
• June through November, March through May 1,200
  MW
• December through February 0 MW

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OP-4 Load Relief

• Load Relief values based on ISO-NE Operating
  Procedure No. 4 (OP-4)

2005-2006 Power Year OP-4 Load Relief (MW) 2005-2006 Power Year OP-4 Load Relief (MW) 2005-2006 Power Year OP-4 Load Relief (MW) 2005-2006 Power Year OP-4 Load Relief (MW) 2005-2006 Power Year OP-4 Load Relief (MW)
(A) (B) (C) (BC-A)
Minimum Operating Reserve OP-4 Actions 9 10 5 Voltage Reduction Total OP-4 Load Relief
June September 200 45 395 240
October - May 200 45 342 187

• 5 Voltage Reduction is based on 1.5 of the
  seasonal peak load as determined by Spring
  Voltage Reduction Test Results

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Tie Reliability Benefits Scenarios

• The PSPC suggested calculating NEPOOL OC for
  2005/06 Power year with two sets of tie
  reliability benefits assumptions. The results
  are

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2005-2006 Power Year Objective Capability
Values Assuming ISO Recommended HQICC Values (MW)
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2004-2005 Power Year Objective Capability
Values (MW)
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ISO-NE OC Recommendation

• ISO-NE recommends that the NEPOOL Objective
  Capability for the Power Year commencing on June
  1, 2005 and ending on May 31, 2006 be those
  associated with assuming 2,000 MW of tie
  reliability benefits.

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Appendix

• Examples of LOLE calculation

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Capacity Outage Calculation
Two Identical Units 100 MW RatingEquivalent
Forced Outage Rate 0.10
Assuming that the load is 100 MW, then the
probability of not being able to serve the load
is 0.01
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Capacity Outage Calculation (Contd)
Three Identical Units 50 MW RatingEquivalent
Forced Outage Rate 0.05
Assuming that the load is 100 MW, then the
probability of not being able to serve the load
is 0.00715 0.000125 0.00725
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Capacity Outage Calculation (Contd)
Four Identical Units 50 MW Rating Equivalent
Forced Outage Rate 0.05
Assuming that the load is 100 MW, then the
probability of not being able to serve the load
is 0.000475 0.00000625 0.0004813
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