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

NEPOOL Objective Capability

(Installed Capacity Requirement)For Power Year 2005/2006

Presentation to the

NEPOOL Power Supply Planning Committee

January 28, 2005

Holyoke, MA

ISO NEW ENGLAND | The people behind New England’s power 2

BackgroundNEPOOL 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.


Background (Cont’d)

• 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.



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.



The Capacity Model uses probabilistic calculation that simulates the availability of system resources (taking into account each generating unit’s 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.


Consider two Generators – one of 100 MW capability, and another of 200 MW.

Their binary (full capacity up, or full capacity down) behaviors are:

Gen. Cap. OutageProbability.

#1 100 0.1 (10%) Representation#2 200 0.15 (15%)

0.9

0.1

0.850.15

0

0

100

200

prob

abil

ity

Capacity on outage

Joint outcomesAvailable Cap. On Prob.

State Cap. Outage

Gen. #1 up, Gen. #2 up 100 + 200 = 300 0 0.9 * 0.85 = 0.765Gen. #1 down, Gen. #2 up 0 + 200 = 200 100 0.1 * 0.85 = 0.085Gen. #1 up, Gen #2 down 100 + 0 =100 200 0.9 * 0.15 = 0.135Gen. #1 down, Gen #2 down 0 + 0 = 0 300 0.1 * 0.15 = 0.015

1.00

Capacity outage probability table (distribution)

0 100 200 300

0.765

0.085 0.135 0.015

Consider two Generators – one of 100 MW capability, and another of 200 MW.

Their binary (full capacity up, or full capacity down) behaviors are:

Gen. Cap. OutageProbability.

#1 100 0.1 (10%) Representation#2 200 0.15 (15%)

0.9

0.1

0.850.15

0

0

100

200

prob

abil

ity

Capacity on outage

Joint outcomesAvailable Cap. On Prob.

State Cap. Outage

Gen. #1 up, Gen. #2 up 100 + 200 = 300 0 0.9 * 0.85 = 0.765Gen. #1 down, Gen. #2 up 0 + 200 = 200 100 0.1 * 0.85 = 0.085Gen. #1 up, Gen #2 down 100 + 0 =100 200 0.9 * 0.15 = 0.135Gen. #1 down, Gen #2 down 0 + 0 = 0 300 0.1 * 0.15 = 0.015

1.00

Capacity outage probability table (distribution)

0 100 200 300

0.765

0.085 0.135 0.015


Consider a demand of 180 MW in a single hour. Reserve capacity= Installed capacity – load= 300 – 180 =120 MW.

Hence, if the capacity on outage is greater than the reserve cap. (120 MW), curtailment is necessary.

0 100 300

0.765

0.085 0.135 0.015

200Capacity on outage

120

MW

Probability of loss of > 120 MW = 0.135 + 0.015 = 0.15.

If we continue this procedure for 7200 hours corresponding to 300 working days of the year, let the average loss of load probability (LOLP) computed be 0.002. This is expressed as a mathematical expectation as the no. of expected hours = 0.002 * 7200 = 14.4 hours per year, or as 14.4 / 24 = 0.6 days per year. This mathematical expectation is expressed as loss of load expectation (LOLE).

Similarly, let the demand in another hour be 99 MW. Then, since reserve = 300 –99 = 201 MW, curtailment results if more than 201 MW is on outage. This, from the above distribution, is equal to0.015. Over a period of two hours, the average probability of loss of load (if we value, or weight,them equally) is (0.15 +0.015) / 2 = 0.0825.

This is the probability of curtailment , or probability of loss of load.

Consider a demand of 180 MW in a single hour. Reserve capacity= Installed capacity – load= 300 – 180 =120 MW.

Hence, if the capacity on outage is greater than the reserve cap. (120 MW), curtailment is necessary.

0 100 300

0.765

0.085 0.135 0.015

200Capacity on outage

120

MW

Probability of loss of > 120 MW = 0.135 + 0.015 = 0.15.

If we continue this procedure for 7200 hours corresponding to 300 working days of the year, let the average loss of load probability (LOLP) computed be 0.002. This is expressed as a mathematical expectation as the no. of expected hours = 0.002 * 7200 = 14.4 hours per year, or as 14.4 / 24 = 0.6 days per year. This mathematical expectation is expressed as loss of load expectation (LOLE).

Similarly, let the demand in another hour be 99 MW. Then, since reserve = 300 –99 = 201 MW, curtailment results if more than 201 MW is on outage. This, from the above distribution, is equal to0.015. Over a period of two hours, the average probability of loss of load (if we value, or weight,them equally) is (0.15 +0.015) / 2 = 0.0825.

This is the probability of curtailment , or probability of loss of load.


Assuming that the load is 100 MW, then the probability of not being able to serve the load is 0.01

Capacity Outage (MW) unit-1 unit-2

0 up up 0.9*0.9 0.81 0.81down up 0.1*0.9 0.09

up down 0.9*0.1 0.09200 down down 0.1*0.1 0.01 0.01

Unit Status

Probability

100 0.18

Two Identical Units – 100 MW RatingEquivalent Forced Outage Rate = 0.10

Capacity Outage Calculation


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

Three Identical Units – 50 MW RatingEquivalent Forced Outage Rate = 0.05

Capacity Outage (MW) unit-1 unit-2 unit-3

0 up up up 0.95*0.95*0.95 0.85738 0.857375down up up 0.05*0.95*0.95 0.04513

up down up 0.95*0.05*0.95 0.04513up up down 0.95*0.95*0.05 0.04513

down down up 0.05*0.05*0.95 0.00238down up down 0.05*0.95*0.05 0.00238

up down down 0.95*0.05*0.05 0.00238150 down down down 0.05*0.05*0.05 0.00013 0.000125

Unit Status

50

100

Probability

0.135375

0.007125

Capacity Outage Calculation (Cont’d)


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

Four Identical Units – 50 MW Rating Equivalent Forced Outage Rate = 0.05

Capacity Outage (MW) unit-1 unit-2 unit-3 unit-4

0 up up up up 0.95*0.95*0.95*0.95 0.8145063 0.81450625down up up up 0.05*0.95*0.95*0.95 0.0428688

up down up up 0.95*0.05*0.95*0.95 0.0428688up up down up 0.95*0.95*0.05*0.95 0.0428688up up up down 0.95*0.95*0.95*0.05 0.0428688

down down up up 0.05*0.05*0.95*0.95 0.0022563down up down up 0.05*0.95*0.05*0.95 0.0022563down up up down 0.05*0.95*0.95*0.05 0.0022563

up down down up 0.95*0.05*0.05*0.95 0.0022563up down up down 0.95*0.05*0.95*0.05 0.0022563up up down down 0.95*0.95*0.05*0.05 0.0022563

down down down up 0.05*0.05*0.05*0.95 0.0001188down down up down 0.05*0.05*0.95*0.05 0.0001188down up down down 0.05*0.95*0.05*0.04 0.0001188

up down down down 0.95*0.05*0.05*0.05 0.0001188200 down down down down 0.05*0.05*0.05*0.05 0.0000063 0.00000625

Unit Status

50

Probability

0.1714750

150 0.0004750

100 0.0135375

Capacity Outage Calculation (Cont’d)


AssumptionsFor 2005/06 OC Calculations


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


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


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)


Capacity• Capacity Additions

– Ridgewood Generation (8.4 MW)

– Kendall Steam 3 Reactivation (25 MW)

– Kendall CT Reactivation (158 MW)

• Capacity Attrition

– No attrition assumed


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.


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.


[1] Calculated using a Capacity weighted average of the August 20, 2004 performance audit results(non emergency generation capacity) and the NERC Class average EFORd value of 7.45%

Program Load ZoneMW Assumed in 05/06

OC Calculations 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 315.8

EFOR values based on Aug. 20, 2004 audit results and NERC Class average data

Assumed MW from Load Response Program


Emergency Resources

• SWCT RFP

– Contracted SWCT RFP resources not currently enrolled in Real-Time Demand Response included

– 218 MW total contracted for summer 2005


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

EFOR =Equivalent Forced Outage Hours

(Period Hours – Scheduled Outage Hours)


EFORd Equation

Where:

D1

+ T1

+ r1

T1

+ r1

f f

EFOR

f FOH f EFOH - FOH

SH f FOHD

f p

f

r = average forced outage duration = FOH

number of forced outages

T average time between calls for a unit to run = RSH

number of attempted starts

D = average run time = SH

number of successful starts

f SH

AHp


• 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


• 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.

Equiv. Forced Outage Rate – Demand (EFORd)


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 Jan’00 – Feb’03

– Calculated EFORd using GADs used Mar’03 – Dec ’04

• Since Dec 04 data is not yet available,Dec 03 data is used for Dec 04.


Unit Availability

• New England Nuclear units performance not correctly represented by NERC Class Average EFORd

• For Nuclear units, used ISO-NE calculated Jan’00 through Feb’03 EFOR and Mar’03 through Dec’04 EFORd.– Since Dec 04 data is not yet available,

Dec 03 data is used for Dec 04.


Results of 60-Month Average

Unit CategorySummer

MW% of

System05/06 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

Nuclear4,387 14.2 1.35

Hydro(Includes Pumped Storage)

3,340 10.8 3.80

Total System 30,940 100 5.41


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)


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 and May – 1,200

MW– December through February – 0 MW


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)

(A) (B) (C) (B+C-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


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:


Table 1 - 05/06 OC Values Assuming 2,000 MW Tie Benefits

TOTAL MONTHLY CAPABILITY

Jun-05 Jul-05 Aug-05 Sep-05 Oct-05 Nov-05 Dec-05 Jan-06 Feb-06 Mar-06 Apr-06 May-06Internal Installed Capacity* 31,620 31,529 31,527 31,550 34,077 34,090 34,089 34,075 34,087 34,099 34,099 34,095 Ties 2,000 2,000 2,000 2,000 1,200 1,200 - - - 1,200 1,200 1,200 NYPA 81 81 81 81 81 81 81 81 81 81 81 81 Expansion Unit Capacity - - - - - - - - - - - - OP4 240 240 240 240 188 188 188 188 188 188 188 188 Cap 33,941 33,850 33,848 33,871 35,546 35,559 34,358 34,344 34,356 35,568 35,568 35,564 * Includes Vermont External Contracts with HQ

OBJECTIVE CAPABILITY CALCULATION DETAILS

Jun-05 Jul-05 Aug-05 Sep-05 Oct-05 Nov-05 Dec-05 Jan-06 Feb-06 Mar-06 Apr-06 May-06APk 26,355 26,355 26,355 26,355 26,355 26,355 26,355 26,355 26,355 26,355 26,355 26,355 Cap 33,941 33,850 33,848 33,871 35,546 35,559 34,358 34,344 34,356 35,568 35,568 35,564 Ties 2,000 2,000 2,000 2,000 1,200 1,200 - - - 1,200 1,200 1,200 OP4 240 240 240 240 188 188 188 188 188 188 188 188 ALCC 2,550 2,550 2,550 2,550 2,550 2,550 2,550 2,550 2,550 2,550 2,550 2,550 HQ 1,200 1,200 1,200 1,200 1,200 1,200 - - - 1,200 1,200 1,200 NYPA 81 81 81 81 81 81 81 81 81 81 81 81 50% Hydro 68 59 68 69 56 36 32 32 38 18 9 24 OC 30,092 30,000 30,007 30,029 32,320 32,312 31,107 31,094 31,111 32,302 32,293 32,304 ** 800 MW Tie Benerfits (600 MW NY, 200 MW NB) June-Sept

HIQCC equals those values as recommended by ISO-NE on 1/28/2005 based on HQ provided data

2005-2006 Power Year Objective Capability (OC)January 28, 2005


Table 2 - 05/06 OC Values Assuming 1,400 MW Tie Benefits

TOTAL MONTHLY CAPABILITY

Jun-05 Jul-05 Aug-05 Sep-05 Oct-05 Nov-05 Dec-05 Jan-06 Feb-06 Mar-06 Apr-06 May-06Internal Installed Capacity* 31,620 31,529 31,527 31,550 34,077 34,090 34,089 34,075 34,087 34,098 34,099 34,095 Ties 1,400 1,400 1,400 1,400 1,200 1,200 - - - 1,200 1,200 1,200 NYPA 81 81 81 81 81 81 81 81 81 81 81 81 Expansion Unit Capacity - - - - - - - - - - - - OP4 240 240 240 240 188 188 188 188 188 188 188 188 Cap 33,341 33,250 33,248 33,271 35,546 35,559 34,358 34,344 34,356 35,567 35,568 35,564 * Includes Vermont External Contracts with HQ

OBJECTIVE CAPABILITY CALCULATION DETAILS

Jun-05 Jul-05 Aug-05 Sep-05 Oct-05 Nov-05 Dec-05 Jan-06 Feb-06 Mar-06 Apr-06 May-06APk 26,355 26,355 26,355 26,355 26,355 26,355 26,355 26,355 26,355 26,355 26,355 26,355 Cap 33,341 33,250 33,248 33,271 35,546 35,559 34,358 34,344 34,356 35,567 35,568 35,564 Ties 1,400 1,400 1,400 1,400 1,200 1,200 - - - 1,200 1,200 1,200 OP4 240 240 240 240 188 188 188 188 188 188 188 188 ALCC 1,945 1,945 1,945 1,945 1,945 1,945 1,945 1,945 1,945 1,945 1,945 1,945 HQ 1,200 1,200 1,200 1,200 1,200 1,200 - - - 1,200 1,200 1,200 NYPA 81 81 81 81 81 81 81 81 81 81 81 81 50% Hydro 68 59 68 69 56 36 32 32 38 18 9 24 OC 30,709 30,616 30,623 30,645 32,985 32,977 31,773 31,759 31,776 32,967 32,958 32,970 ** 200 MW Tie Benerfits (150 MW NY, 50 MW NB) June-Sept

HIQCC equals those values as recommended by ISO-NE on 1/28/2005 based on HQ provided data

2005-2006 Power Year Objective Capability (OC)January 28, 2005


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 from Table 1, developed using 2,000 MW of

tie reliability benefits (including HQICC).

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

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