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PJM Manual for

Generator Unavailability Subcommittee

Reference Manual

Manual M-22

Revision: 12

Effective Date: August 23, 2000

Prepared by

Generator Unavailability Subcommittee

PJM Interconnection, L.L.C.

Copyright 2000

PJM Interconnection, L.L.C.

ALL RIGHTS RESERVED


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PJM Interconnection, L.L.C. i

Revision 12, Effective Date: 08/23/00M22T01V12.doc

Generator Unavailability Subcommittee Reference Manual

Table of Contents

Revision History

Approval ......................................................................................................................REV-1

Revision History .......................................................................................................... REV-1

Introduction

About PJM Manuals..................................................................................................... INT-1

About This Manual ....................................................................................................... INT-2

Target Users............................................................................................................. INT-2

References................................................................................................................ INT-3

Using This Manual ....................................................................................................... INT-4

What Youll Find In This Manual ........................................................................... INT-4

Section 1: Scope of Responsibility

Generator Unavailability Subcommittee .......................................................................... 11

Section 2: Acronyms

Acronym Listing.................................................................................................................2-1

Section 3: Definitions and Equations

Definitions .........................................................................................................................3-1

Equations..........................................................................................................................3-4

Section 4: Periodic Reports

Introduction .......................................................................................................................4-1

Planning Study Outage Data Report.................................................................................4-1


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Table of Contents

PJM Interconnection, L.L.C. ii

Revision 12, Effective Date: 08/23/00M22T01V12.doc

Data for Units with Five Full Calendar Years of Operating Experience......................4-2

Data for Units with Less Than Five Full Calendar Years of Operating Experience and

Future Units ..................................................................................................................4-3

Class Average Outage Rates .............................................................................................4-6

Section 5: Miscellaneous Documentation

Item A: Full f-Factor Derivation .....................................................................................5-1

Item B: Partial f-Factor Derivation .................................................................................5-4

Item C: Modified Two-State Model for Reliability Calculations .....................................5-5

Item D: Rules for Consistency of Generator Outage Rate Calculations..........................5-7

Item E: Capacity Variance Calculation Procedure for Existing Units ............................5-9

Item F: Generator Unavailability Subcommittee Programs ..........................................5-12

Exhibit I.1: List of PJM Manuals..................................................................................... INT-1

Exhibit 4.1: Class Average Outage Rates .............................................................................4-6

Exhibit 5.1: Generator States ................................................................................................5-1

Exhibit 5.2: Partial f-Factor Time Period.............................................................................. 5-4


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PJM Interconnection, L.L.C REV1

Revision 12, Effective Date: 08/23/00M22H01V12.doc

Revision History

Approval

Approval Date: 08/23/2000Effective Date: 08/23/2000

R. O. Hinkel, Manager

Capacity Adequacy Planning

Revision History

Revision 12 (08/23/2000)

Modified text to refer to "Class Average Outage Rates" instead of "Table III". Reviewed for

compliance with RAA.

Revision 11 (06/01/99)

Removed all references to Supplemental Agreement, removed references to data and

procedures no longer supported and reformatted document for publishing on the PJM

website.

Revision 10 (04/01/96)

Revision 09 (11/01/94)

Revision 08 (10/01/94)

Revision 07 (07/01/94)

Revision 06 (02/01/93)

Revision 05 (09/01/92)

Revision 04 (12/01/91)

Revision 03 (03/01/87)

Revision 02 (05/01/86)

Revision 01 (02/01/85)


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Revision History

PJM Interconnection, L.L.C. REV2

Revision 12, Effective Date: 08/23/00M22H01V12.doc

Issued (04/01/84)


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PJM Interconnection, L.L.C. INT1

Revision 12, Effective Date: 08/23/2000M22I01V12.doc

Introduction

Welcome to the PJM Manual forGenerator Unavailability Subcommittee Reference. In this

Introduction, you will find the following information:

What you can expect from the PJM Manuals in general (see About PJM Manuals).

What you can expect from this PJM Manual (see About This Manual).

How to use this manual (see Using This Manual).

About PJM Manuals

The PJM Manuals are the instructions, rules, procedures, and guidelines established by PJM

OI for the operation, planning, and accounting requirements of the PJM Control Area and

the PJM Energy Market. Exhibit I.1 lists the PJM Manuals.

M01 - Control Center Requirements

PJM

Energy

Market

Transmission

Reserve

PJM

Accounting& Billing

M02 - Transmission Service

Requests

M03 - Transmission Operations

M04 - PJM OASIS Operation

M05 - Data Management

M06 - Fixed

Transmission Rights

M13 - Emergency Operations

M12 - Dispatching Operations

M11 - Scheduling Operations

M10 - Pre-Scheduling Operations

M14 - Generator

Interconnections & Operations

M22 - Generator Unavailability Subcommittee

Reference Manual

M21 - Rules and

Procedures for Determination of Generating Capability

M20 - PJM Reserve Requirements

M19 - Load Data Systems

M18 - Installed Capacity: Generation

Data Systems

M17 - Accounted-For Obligation

M33 - Administrative Services for the PJM Inter-

connection Agreement

M31 - Customer Choice

M29 -Billing

M28 -Operating Agreement Accounting

M27-Open Access Transmission Tariff Accounting

Exhibit I.1: List of PJM Manuals


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Introduction



About This Manual

The PJM Manual forGenerator Unavailability Subcommittee Referenceis one of a series of

manuals within the Reserve group of manuals. This manual focuses on the responsibilities of

the PJM Generator Unavailability Subcommittee in all matters concerning the projection ofgenerating unit unavailabilities, as required for PJM Reliability and Capacity Allocation

studies and also for other data required for specific planning applications.

The PJM Manual forGenerator Unavailability Subcommittee Referenceconsists of five

sections. The sections are as follows:

Section 1:Scope of Responsibility

Section 2: Acronyms


Section 4:Periodic Reports


Target Users

The target users for the PJM Manual forGenerator Unavailiability Subcommittee Reference

are:

PJM Board of Managers The PJM Board Members are responsible for theadministration and approval of the forecast obligation and techniques for determination.

RAA Reliability Committee Reliability Committee members are responsible for thereview and submittal of the obligations with review of the PJM Board of Mangers.

PJM OI system planning staff PJM Staff are responsible for the calculation andsubmittal for approval of the zonal diversity factors, installed reserve requirement, pool

forced outage rate, forecast pool requirement, weather normalized coincident zonal

peaks, peak period available ALM, and the PJM ALM load factor. These quantities are

required to meet the RAA mandate of establishment of these quantities before April 30

for applicable future planning periods.

Other PJM Agreement signatory staff The staff are responsible for supplying loadand generator data in the required format and time period to assist in the calculation and

submittal of required quantities.

PJM OI audit staff Auditors are responsible for ensuring Agreements of PJMInterconnection, L.L.C. are fair and consistent among the parties.

PJM OI marketing services staff The PJM OI Marketing Services staff areresponsible for monthly billing and maintenance of the accounted-for input data.


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Generator Unavailabiltiy Subcommittee Reference Manual

Introduction



References

There are several references that provide background and details.

FERC Order No. 888

PJM Interconnection Agreement PJM Manual forLoad Data System

PJM Manual forInstalled Capacity: Generation Data Systems

PJM Manual forRules and Procedures for Determination of Generating Capability

PJM Manual forBilling

The PJM Manual forGenerator Unavailability Subcommittee Referencedoes not replace

any information in the reference documents. The reference documents are the primary

source for specific requirements and implementation details.


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Generator Unavailabiltiy Subcommittee Reference Manual

Introduction



Using This Manual

Because we believe that explaining concepts is just as important as presenting the

procedures, we start each section with the big picture. Then, we present details and

procedures. This philosophy is reflected in the way we organize the material in this manual.The following paragraphs provide an orientation to the manuals structure.

What Youll Find In This Manual

A table of contents

An approval page that lists the required approvals and the revision history

This introduction

Sections containing the specific guidelines, requirements, or procedures including PJMOI actions and PJM Member actions


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PJM Interconnection, L.L.C. 1-1

Revision 12, Effective Date: 08/23/00M22S01V12.doc

Section 1: Scope of Responsibility

GENERATOR UNAVAILABILITY SUBCOMMITTEE

The PJM Generator Unavailability Subcommittee (GUS) is responsible to the PJM PlanningCommittee (PC) in all matters concerning the projection of generating unit unavailabilities,

as required for PJM Reliability and Capacity Allocation studies. The Subcommittee shall

also be responsible for other data required for specific planning applications.

To execute this charge, the Subcommittee shall develop and maintain unavailability rate

definitions consistent with the purposes defined above. The Subcommittee shall also

monitor and assess industry outage trends and tools to determine their utilization for PJM

applications.

The Subcommittee is responsible for the preparation of "Forced Outage Rates and Scheduled

Outage Data for Planning Studies." This document provides data for Capacity Allocationand Reserve Requirement studies.

The Subcommittee shall also maintain, but will not be limited to, the PJM Generator Outage

Rate Program (webGORP) for historical data analysis.

Specific activities include:

(1)Review recommended changes to the NERC Index To System/Component Cause Codes

(2)Update, annually, the "Forced Outage Rates and Scheduled Outage Data for PlanningStudies."

(3)Provide projections of class average outage rates for new units.

(4)Monitor the industry for general trends and outage rate calculation tools.

(5)Provide miscellaneous reports and statistics required by other Committees and/orSubcommittees.

(6)Recommend refinements in PJM outage data collection procedures (eGADS), asrequired.


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PJM Interconnection, L.L.C 2-1


Section 2: Acronyms

Acronym Listing

EEI - Edison Electric Institute

GADS - Generating Availability Data System

GCRPTF - PJM Generating Capability Rating Procedures Task Force

GEBGE - General Electric, Baltimore Gas & Electric Reliability Program

GORP - Generator Outage Rate Program

GUS - PJM Generator Unavailability Subcommittee

GUSOUT- Synonym for GORP

IEEE - Institute of Electrical and Electronic Engineers

L&CS - PJM Load and Capacity Subcommittee

NERC - North American Electric Reliability Council

OC - PJM Operating Committee

PC - PJM Planning Committee

FOR - Forced Outage Rate

EFORD - Equivalent Demand Forced Outage Rate

EEFORD - Effective Equivalent Demand Forced Outage Rate

EFOF - Equivalent Forced Outage Factor

MOF - Maintenance Outage Factor

EMOF - Equivalent Maintenance Outage Factor

POF - Planned Outage Factor


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Section 2: Acronyms



EPOF - Equivalent Planned Outage Factor

SOF - Scheduled Outage Factor

OAF - Operating Availability Factor

EAF - Equivalent Availability Factor

AH - Available Hours

FOH - Full Forced Outage Hours

FPOH - Forced Partial Outage Hours

EFOH - Equivalent Full Forced Outage Hours

EFPOH - Equivalent Forced Partial Outage Hours

MOH - Full Maintenance Outage Hours

MPOH - Maintenance Partial Outage Hours

EMOH - Equivalent Full Maintenance Outage Hours

EMPOH - Equivalent Maintenance Partial Outage Hours

PH - Period Hours

POH - Full Planned Outage Hours

PPOH - Planned Partial Outage Hours

EPOH - Equivalent Full Planned Outage Hours

EPPOH - Equivalent Planned Partial Outage Hours

EPOEF - Equivalent Planned Outage Extension Factor

RSH - Reserve Shutdown Hours

SH - Service Hours


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Section 2: Acronyms



UOH - Unplanned Outage Hours

fp - partial f-factor

ff - full f-factor


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Definitions

Forced Outage: An outage that cannot be postponed beyond the end of the next weekend.

Maintenance Outage: An outage that can be postponed beyond the end of the next weekend,

but requires the unit be removed before the next planned outage.

Planned Outage: An outage of predetermined length that is scheduled well in advance of its

occurrence. The outage must be included in a regularly issued maintenance schedule at least

one month prior to the starting date of the outage; i.e., the outage must appear in two

consecutive issues of the PJM Unit Maintenance Schedule prior to starting the outage.

Non-curtailing Outage: The removal from service of spare or redundant equipment (i.e.,

major components or entire systems) for repairs which causes no unit outage or capacityreduction.

Postponability Code 9 Outage: A routine, periodic outage (e.g., deslagging, condenser

cleaning, etc.) which both starts and ends during a single valley load period (i.e., the time

period from 22:00:01 to 08:00:00, inclusive).

Period Hours: The total clock time in the period of concern.

Service Hours: The time a unit is electrically connected to the system.

Reserve Shutdown Hours: The time a unit is available for service but not dispatched due to

economics or other reasons.

Available Hours: The time a unit is capable of producing energy, regardless of its capacity

level.

Demand Hours: The time interval each day on a particular system in which there is a heavy

demand for electricity. For PJM, it is the time period beginning 8:00:01 and ending 22:00:00,

inclusive.


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Generator Unavailability Subcommittee Refernce Manual




Equivalent Outage Hours: The number of hours a unit was involved in an outage, expressed as

equivalent hours of full outage at its maximum net dependable capacity. Equivalent hours can be

calculated for forced, maintenance, or planned outages. Overlapping partial outage hours are not

permitted in PJM outage rate calculations and overlaps are eliminated according to an outage type

hierarchy. (Refer to Equation 1, page 3-4.)

Equivalent Demand Forced Outage Rate: The portion of time a unit is in demand, but is

unavailable due to a forced outage. (Refer to Equation 2, page 3-4.)

Equivalent Forced Outage Factor: The portion of time a unit is unavailable due to forced outages.

(Refer to Equation 3, page 3-4.)

EPOEF: The ratio of EPOF (with SEs included) to EPOF (with SEs excluded).

Equivalent Maintenance Outage Factor: The portion of time a unit is unavailable due to

maintenance outages. (Refer to Equation 4, page 3-5.)

Equivalent Planned Outage Factor: The portion of time a unit is unavailable due to planned

outages. (Refer to Equation 5, page 3-5.)

Operating Availability Factor: The portion of time a unit is available to operate.

Equivalent Availability Factor: The portion of time a unit is available to operate, recognizing

equivalent partial outage time. (Refer to Equation 7, page 3-5.)

Effective Equivalent Demand Forced Outage Rate: The forced outage rate used for reliability and

reserve margin calculations. (Refer to Equation 8, page 3-5.)

Equivalent Scheduled Outage Factor: The planned outage rate used for reliability and reserve

margin calculations. (Refer to Equation 9, page 3-6.)

Variance: A measure of the variability of a units partial forced outages which is used in reserve

margin calculations.

f-factor: Factors which have been adopted by PJM to scale the total number of forced outage hours

to reflect those which occur during demand hours. Separate factors exist to adjust full (ff) and partial

(fp) outage hours. (Refer to Equation 10, page 3-6.)

Planning Period: The continuous time period beginning 00:00:01 on June 1 of a given year andending 24:00:00 on May 31 of the following year.

Mature Unit: A unit having at least five full calendar years of operating experience for Planning

Study usage or at least five full calendar years of operating experience for reliability calculations.


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Immature Unit: A unit having between zero and five full calendar years of operating experience for

Planning Study usage or between zero and five full calendar years of operating experience for

reliability calculations.

Future Unit: A unit to be placed in service at some future time, as indicated in a forecast installed

capacity schedule.

Inactive Status: The classification of a unit which is unavailable for an extended period of time

because of its removal from service for economic or non-equipment related reasons.

Mothballed Unit: A unit placed on inactive status.


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Equations

(1)Equivalent Outage Hours: The following equation is applicable to forced, maintenance andplanned capacity derations.

=

iC

)i

Ti

(D

iE*

where:

hours,outageequivalentE=

MW,i,outageforderationcapacityDi =

andhours,i,outageduringdaccumulatetimeTi =

MWoutage,thisoftimetheatcapacitydependablenetmaximumunitCi =

NOTE: The capacity can change if the outage extends over 1 or more months.

(2)Equivalent Demand Forced Outage Rate:

FOHEFOHEFPOHNote

FOH*f

fSH

EFPOH)*p

fFOHf

(f

(%)D

EFOR

*

=

+

+=

:

%100*

(3)Equivalent Forced Outage Factor:

=

=

+==

168*n

PH

PH

EFOHyearweeksEFOF

or

FOHEFOHEFPOHNote

PH

EFPOHFOH

PH

EFOH(%)EFOF

*)/(

:

%100*%100*

where n is the number of years of accumulated outage hours.


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(4)Equivalent Maintenance Outage Factor:

=

=

+==

168*n

PH

PH

EMOHyearweeksEMOF

or

MOHEMOHEMPOHNote

PH

EMPOHMOH

PH

EMOH(%)EMOF

*)/(

:

%100*%100*


(5)Equivalent Planned Outage Factor:

=

=

+==

168*n

PH

PH

EPOHyearweeksEPOF

or

POHEPOHEPPOHNote

PH

EPPOHPOH

PH

EPOH(%)EPOF

*)/(

:

%100*%100*


(6)Equivalent Planned Outage Extension Factor:

=excluded)(w/SEEPOF

included)(w/SEEPOFEPOEF

(7)Equivalent Availability Factor:

%100*

++=

PH

EPPOH)EMPOH(EFPOH-AH(%)EAF

(8)Effective Equivalent Demand Forced Outage Rate:(1)

(%)*(%) EMOF4

1

DEFOR(%)

DEEFOR

+=


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(9)Equivalent Scheduled Outage Factor:(1)

The equivalent scheduled outage factor can be expressed in either % or weeks/year using the

equation:

EMOF4

3EPOFESOF *

+=

(1)Since GEBGE can only accommodate two outage rates, the maintenance outage factor must be

allocated to one, or both, of these rates. A rationale for proportioning it as shown is contained in the

document "Report on the Study of Load Models and Reliability Program Features," Section I -

GEBGE Options, pages 5-7 (Random Maintenance), issued March, 1972 by the PJM Capacity and

Transmission Planning Subcommittee. The original decision, presumably made by the PJM Planning

and Engineering Committee, predates the indicated report.

(10) f-factors:(2,3)

+++

=1/D1/T1/r

1/T1/r

ff

where:

outages)forcedof(number

FOHdurationoutageforcedaverager ==

starts)attemptedof(number

RSH

runtounitaforcallsbetweentimeaverageT

==

starts)lsuccessfuof(number

SHtimerunaverageD ==

and

=

AH

SH

pf

(2) The full f-factor was adopted for use by PJM with the acceptance of the "Report on GeneratingUnit Outage Definitions" issued in November, 1972 by the PJM Operating and P&E Committees.

Refer to Section V, Item A, page 25 for the derivation of the full f-factor.


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(3) The current definition of the partial f-factor was proposed by the Generator Unavailability

Subcommittee, and approved for use by the Planning and Engineering Committee at its 260th

meeting held March 8, 1982.


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Introduction

The Generator Unavailability Subcommittee is required to periodically compile and issueseveral reports for use by other groups within PJM. These reports provide outage rate

information needed to perform reliability, reserve requirement, allocation of forecast reserve

requirement and production studies for the Interconnection. The principal report is the

Planning Study Outage Data Report due to the Planning Committee February 1 of each year.

Planning Study Outage Data Report

Planning study outage data is primarily intended for use by the Load and Capacity

Subcommittee to determine the PJM capacity reserve requirements. This data is also used to

determine the Forced Outage Rate (F).

The report provides Effective Equivalent Demand Forced Outage Rates (EEFORd), capacity

variances and scheduled outage data for all existing and future units included in the latest

capacity schedule of each company. This information is based on the latest five full calendar

years of operating experience and excludes I.O. code 9 outages (i.e., routinely occurring

off-peak outages).

Future capacity additions, deletions and modifications are based on data as provided for

inclusion in the most recent EIA-411/860 report. Additional data available at the PJM Office of

the Interconnection on possible planned additions is also taken into account.

The outage data source for this report is the PJM eGADS database which includes the outagehistory for the calendar year just ended. One run must contain "Unit Summary Reports" of

operating experience for each of the last five years and cumulative for the last five years, the

"Probability of Unit Partial Outage State Report" and the "Unit Variance and Partial Outage

State Report." The second run must contain "Unit Summary Reports" of operating experience

for last five years with scheduled extensions of maintenance and planned outages removed.

The incumbent GUS chairman is responsible for compiling and issuing this report. Since the

data included in the report deals with individual units and their operating characteristics the

report is considered to be confidential and is only used at the PJM Office of the

Interconnection.


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Data for Units with Five Full Calendar Years of Operating Experience

(1)Individual Unit Effective Equivalent Demand Forced Outage Rate Calculation:

Included in the Effective Equivalent Demand Forced Outage Rate (EEFORD) calculation is theEquivalent Demand Forced outage rate (EFORD). The annual unit EFORDwill be 100% for

any period of operation after 1992 during which minimum reporting requirements are not met.

Minimum reporting requirements are defined as either GADS event data or actual hourly net

generation for units less than 10 MW. Class Average Outage Rates for EFORDwill be used for

all years prior to the first full year of operation and for all non-reported years prior to 1992.

Companies that are unable to comply with the minimum reporting requirements after 1992 have

the option to appeal to the Planning Committee for an alternative to the 100% EFORDruling.

(a)Mature Unit: The effective equivalent demand forced outage rate (%) of a

mature unit is determined based on the latest five full calendar years of operatingexperience. It is calculated by adding 25% of the equivalent maintenance outage

factor (%) to the equivalent demand forced outage rate (with f-factor). The five-

year cumulative statistics are to be taken directly from the GORP output which

has scheduled extensions included, unless manual adjustments are necessary.

(b)Mothballed Unit: A mothballed unit is ignored until it is reactivated andincluded in the companys installed capacity.

(c)Combined Cycle Conversion of Existing CTs:Combined Cycle units createdby adding heat recovery boilers and steam turbines to existing combustion

turbines will use Class Average Outage Rates until the combined cycle unit hasmature operating history unless granted an exception.

(2)Capacity Variance Calculation:

(a)Mature Unit:The capacity variance (MW2) of a mature unit is calculated usingthe procedure given in Section V, Item E: Capacity Variance Calculation

Procedure for Existing Units. This information is to be taken directly from the

appropriate GORP output and used, unless manual adjustments are required.

(b)Mothballed Unit: A mothballed unit is ignored until it is reactivated and

included in the companys installed capacity.


turbines will use the following variance formula until the combined cycle unit has

mature operating history unless granted an exception.


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DEEFOR*)

DEEFOR-(1*

2MWV =

(3)Scheduled Outage Data Calculation:

(a)Mature Unit:The scheduled outage data of a mature unit is calculated based onthe latest five full calendar years of operating experience and the "Ten Year Unit

Planned Maintenance Forecast". Ten years of scheduled outage weeks are

determined for each unit by multiplying the forecast maintenance weeks by the

EPOEF (equation 6) and adding to each 75% of the EMOF (weeks/year). The

five-year cumulative statistics are to be taken directly from the appropriate GORP

output and used, unless manual adjustments are necessary.

Data for Units with Less Than Five Full Calendar Years of OperatingExperience and Future Units

(1)Individual Unit Effective Equivalent Demand Forced Outage Rate Calculation:

Included in the Effective Equivalent Demand Forced Outage Rate (EEFORD) calculation is the

Equivalent Demand Forced outage rate (EFORD).

The annual unit EFORD will be 100% for any period of operation after 1992 during which

minimum reporting requirements are not met. Minimum reporting requirements are defined as

either GADS event data or actual hourly net generation for units less than 10 MW. Table III

values for EFORDwill be used for all years prior to the first full year of operation and for all

non-reported years prior to 1992.

Companies that are unable to comply with the minimum reporting requirements after 1992 havethe option to appeal to the Planning and Engineering Committee for an alternative to the 100%

EFORDruling.

(a)Immature Unit: The effective equivalent demand forced outage rate of animmature unit is the weighted combination of its historical and class-average

rates (i.e., Class Average Outage Rates). For example, the rate for a unit with n

full calendar years of operating experience is:

IIITable

DEEFORnhistorical

DEEFORn

(%)D

EEFOR

+=

5

)(%,*)5()(%,*

where EEFORD(%, historical) must be manually calculated using Equations 2, 4 and 8

given in Section 3, pages 5 and 6.


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(b)Future Unit:The effective equivalent demand forced outage rate (%) of a futureunit is the class-average rate for its size and type indicated in the Class Average

Outage Rates of this report.

(c)Combined Cycle Conversion of Existing CTs:Combined Cycle units created

by adding heat recovery boilers and steam turbines to existing combustionturbines will use Table III class average rates until the combined cycle unit has


(2)Capacity Variance Calculation:

(a)Immature Unit:The forced outage capacity variance of an immature unit is theweighted combination of its historical and future unit values. For example, the

variance for a unit with n full calendar years of operating experience is:

futureMW

f

VnhistoricalMW

h

Vn

)2(MW2

+=

5

),2(*)5(),2(*

where Vhis calculated using the procedure given in Section V, Item E and V fis

the future unit variance appropriate for the units size and type indicated in the

Class Average Outage Rates of this report.

(b)Future Unit: The capacity variance (MW2) of a future unit is the valueappropriate for the units size and type indicated in the Class Average Outage

Rates of this report.


turbines will use the following variance formula until the combined cycle unit has


DEEFOR

DEEFOR-(1*

2MWV *)=

(3)Scheduled Outage Data:

(a)Immature Unit: The scheduled outage data for an immature unit is comprisedof the following components:

1) Ten-Year Planned Maintenance Forecast;2) The equivalent planned outage extension factor (EPOEF);3) The equivalent maintenance outage factor (EMOF) in weeks per year;4) Years of service; and5) The ten-year scheduled outage weeks


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The yearly calculation for scheduled outage data for a unit with n full calendar

years of operating experience is:

5/n)-(5*3))](TableEMOF*(0.75(wks/yr)WeeksOutagedScheduleTable

nyrwksEMOFEPOEFyrwksMainPlanned(yearly)OutageScheduled

++

+=

3[

]*)))/(*75.0()*)/(.[((

where EPOEF and EMOF (historical) must be manually calculated using

Equations 6 and 4 respectively as given in Section 3, pages 5 and 6.

(b)Future Unit: The scheduled outage data of future units are assigned theappropriate class-average values for scheduled outages and maintenance cycles

indicated in the Class Average Outage Rates of this report.

(c)Combined Cycle Conversion of Existing CTs: Combined Cycle units createdby adding heat recovery boilers and steam turbines to existing combustion

turbines will use the Class Average Outage Rates values until the combined cycle

unit has mature operating history unless granted an exception.


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Class Average Outage RatesClass Average Outage Rates

PJM Use Effective

December 1999

Item Categories / Classification

Of Generators

EFORd

(%)

Variance

(MW^2)

EEFORd

(%)

ESOF

(Wks/YR)

YR 2

(Wks)

1 - EFORd

(%)1 COAL - 1 99 MW 5.8 252 6.4 4.7 9 94.2

2 COAL - 100 199 MW 5.9 2491 6.6 4.6 10 94.1

3 COAL - 200 299 MW 6.1 3260 6.8 4.9 10 93.9

4 COAL - 300 399 MW 8.4 5311 9.1 5.5 11 91.6

5 COAL - 400 599 MW 8.0 7733 8.6 5.6 11 92.0

6 COAL - 600 799 MW 6.7 8716 7.1 4.6 11 93.3

7 COAL - 800 MW (+) 6.2 12713 6.8 5.2 10 93.8

8 OIL/GAS - 1 99 MW 7.4 234 8.1 3.3 8 92.6

9 OIL/GAS - 100 199 MW 7.5 2779 8.4 4.8 10 92.5

10 OIL/GAS - 200 299 MW 6.1 3388 7.0 5.6 11 93.9

11 OIL/GAS - 300 399 MW 8.2 5917 9.5 6.7 12 91.8

12 OIL/GAS - 400 599 MW 6.9 6782 7.9 5.9 13 93.1

13 OIL/GAS - 600 MW (+) 7.4 11570 8.2 6.4 14 92.6

14 GAS TURB - 1 19 MW 12.9 30 13.4 1.9 3 87.1

15 GAS TURB - 20 49 MW 12.9 69 13.8 2.5 3 87.1

16 GAS TURB - 50 MW (+) 7.2 357 7.7 3.5 4 92.8

17 GAS TURB - All Sizes 10.2 163 10.9 2.7 3 89.8

18 JETS - 1 19 MW 13.5 39 13.9 1.7 3 86.5

19 JETS - 20 MW (+) 9.4 181 10.4 2.8 4 90.6

20 JETS - All Sizes 9.8 146 10.8 2.6 3 90.2

21 HYDRO - 1 29 MW 4.8 5 5.3 2.5 5 95.2

22 HYDRO - 30 MW (+) 3.7 284 4.0 3.5 4 96.3

23 HYDRO - All Sizes 4.1 139 4.5 3.2 4 95.9

24 PUMP - All Sizes 3.8 1381 4.6 6.0 6 96.2

25 DIESEL - All Sizes 7.9 1 8.2 0.5 2 92.1

26 COMB CYC - All Sizes 4.0 1790 5.1 4.4 12 96.0

27 MULTIPLE - All Sizes 7.3 1597 8.3 4.1 8 92.7

28 GEOTH - All Sizes 23.8 1235 26.1 5.2 4 76.2

29 NUC ALL - All Sizes 13.0 56435 13.5 6.7 14 87.0

30 NUC ALL - 400 799 MW 12.0 37954 12.3 7.9 14 88.0

31 NUC ALL - 800 999 MW 13.1 53673 13.6 6.1 14 86.9

32 NUC ALL - 1000 MW (+) 13.4 70258 13.9 6.7 14 86.6

33 NUC PWR - All Sizes 9.7 47242 10.2 6.4 14 90.3

34 NUC PWR - 400 799 MW 3.9 25285 4.2 7.7 14 96.1

35 NUC PWR - 800 999 MW 8.8 41143 9.3 5.5 14 91.2

36 NUC PWR - 1000 MW (+) 12.1 64704 12.7 6.6 14 87.9

37 NUCL BWR - All Sizes 15.2 65162 15.7 7.5 14 84.8

38 NUCL BWR - 400 799 MW 5.3 27997 5.8 8.3 14 94.7

39 NUCL BWR - 800 999 MW 16.3 63552 16.9 8.3 14 83.740 NUCL BWR - 1000 MW (+) 16.4 83553 16.9 6.8 14 83.6

Note:

Coal 800 MW (+) is a combination of two categories, 800 999 MWs and 1000 MWs and Above.

OIL/GAS are combined categories of OIL and GAS units. OIL/GAS 600 MW (+) is a combinations of three categories, 600 799 MWs, 800 999 MWs and 1000MWs and Above.

Data from the 1994 1998 NERC Generator Availability Report

Exhibit 4.1: Class Average Outage Rates


27/39





The outage information contained in this table has been determined by statistical analyses

performed on one or more of the PJM, NRC and NERC/GADS outage event databases. These

analyses are performed periodically, at the discretion of the Generator Unavailability

Subcommittee, to ensure that the values used for future units are reasonable, based on the

historical performance of similar units.

The incumbent GUS chairman is responsible for including the most recent table in this report.


28/39




Item A: Full f-Factor Derivation (*)

The following diagram illustrates the relationships between the potential states in which agenerator can reside. The term governing the transition from one state to another is shown on

the diagram adjacent to the line indicating the direction of the transition.

Exhibit 5.1: Generator States

(*)"A Four-State Model for Estimation of Outage Risk for Units in Peaking Service," Report of

the IEEE Task Group on Models for Peaking Service Units, Application of Probability Methods

Subcommittee, IEEE Transactions on Power Apparatus and Systems, March/April 1972, pages

618-627.

Reserve

Shutdown

State 0

Forced Out

&

Not Needed

State 1

On Line

State 2

Forced Out

&

Needed

State 3

(1-PS) / T

1 / D

PS/ T

1 / T

1 / D

1 / r

1 / r

1 / m


29/39





Terms:

durationoutageforcedaverager =

runtounittheforcallsbetweentimeaverageT =

demandofperiodsduringtimerunaverageD =

outagesforcedbetweentimerunaveragem =

runtocalledisunitthewhenfailurestartaofyprobabilitS

P =

On page 621 of the referenced IEEE paper, the f-factor was defined for use as a mathematical

trick to permit the substitution of known quantities for un- known quantities in the equation

expressing the probability that a unit was unavailable during a demand period (equation 15).

The known quantities were P2(the probability of being in service during a demand period; i.e.,

state 2) and P1+ P3(the probabilities of being forced out during a demand period; i.e., states 1

and 3). Equation 15 is given as

3P

2(P

3P

P)+

=

Define the f-factor as f = P3/ (P1+ P3) and multiply both sides by the term (P1+ P3) to yield

)3

P1

(P*f3

P +=

Now, substitute this equation into equation 15 to eliminate the lone P 3term

)2

)

3P1(P*fP3

P1

(P*fP

+++=

The known quantities of P2and P1+ P3, expressed in hours, are

FOH)(AH

SH

2P

+=

and

FOH)(AH

FOH

3P

1P

+=+

Substituting these equations into the modified equation 15 given above yields

FOH*fSH

FOH*fP

+=


30/39





from which we can see that the f-factor weights the forced outage hours to reflect only that

portion which occur during periods of demand.

Because we still dont know how to separately define P3, we need to redefine the f-factor in

terms of data readily available from recorded outage statistics. Start by defining the frequency

of being in state 1 as

+=

=

T

1

r

1*

1P

1statefromdepartureofrate*1

P1

F

This can also be expressed as

=

=

D

1*

3

P

3statefromentryofrate*3

P1

F

Equating these two expressions and solving for P1yields

T

1

r

1

D

1

*3

P1

P

+=

Substituting this equation into the f-factor definition yields the expression

D

1

T

1

r

1T

1

r

1

f

f

++

+

=

which can be determined from the outage data statistics. This factor is designated as the full

f-factor (ff) because it is used to weight the full forced outage hours.


31/39





Item B: Partial f-Factor Derivation

Exhibit 5.2: Partial f-Factor Time Period

The partial f-factor is a measure of the equivalent full forced outage hours that occur during

times of demand. Theoretically, the partial f-factor is the ratio of the equivalent forced partial

outage hours occurring during demand periods to the total equivalent forced partial outage

hours. Assuming that the partial outages are distributed similarly during service hours and

reserve shutdown hours, then the partial f-factor can be expressed as the ratio of service hours

to the summation of service and reserve shutdown hours. Since available hours equals the

summation of service and reserve shutdown hours, the partial f-factor can be expressed as the

ratio of service hours to available hours, or

AH

SH

pf =

////////////////////////////////////////////

//////////////////////////////////

/////////////////////

//////////

RSH SH MOH + POH

(full)

Capacity

(MW)

Available Hours

Demand Time

FOH (full)

ff* FOH

Forced Partial Outage Hours

Period Hours


32/39





Item C: Modified Two-State Model for Reliability Calculations

The standard two-state model of a generator considers the unit as being either fully available or

fully unavailable. The modified two-state model is a better representation for reliability

calculations because it considers the distribution of outage states possible for a generator. Theresult of using the modified two-state generator availability model is a reduction in the amount

of reserve capacity required to maintain a reliability index of 10 years per day, as compared to

the reserve requirement determined using the standard model.

The standard two-state model calculates the mean available capacity as

C*)D

EEFOR-1(=

where:

MWcapacity,mean

=

andMW,capacity,installedsummernetsunitC =

unit-perrate,outageforceddemandequivalenteffectivesunitD

EEFOR =

The implied capacity variance about the mean with the standard two-state model is

2C*

DEEFOR*)

DEEFOR-1(=2

where:

2MWvariance,=2

This is the maximum variance that can be experienced about the mean with the given effective

equivalent demand forced outage rate. Any representation of partial outage states will tend to

lower the variance.

The modified two-state model preserves both the mean and the variance of the original forced

outage distribution by simultaneously solving the two-state mean and variance equations for

unit capacity and effective equivalent demand forced outage rate using the two-state mean and

variance values. The resulting modified two-state equations are:

DEEFOR-1

C

=

and


33/39





2

2

2

DEEFOR

+=

where:

andMW,capacity,netunitstate-twomodifiedC =

unitperD

EEFORstate-twomodifiedD

EEFOR = ,


34/39





Item D: Rules for Consistency of Generator Outage Rate Calculations(*)

(1)Any errors or inconsistencies found in the PJM Outage Data History File must be corrected.

(2)All revisions to outage rates, for reasons of data integrity, must be accomplished by revisingthe PJM Outage Data History File. If this is not possible, manual revisions to the rates

calculated by the Generator Outage Rate Program must meet the following conditions:

(a)The manual adjustment must be documented and presented to the GeneratorUnavailability Subcommittee no later than one month prior to the rate publication

deadline.

(b)The manual adjustment must be approved by a majority of the Generator UnavailabilitySubcommittee members.

(c)The manual adjustment must be documented in the rate publication.

(d)The discrepancies found in the PJM Outage Data History File which necessitated themanual adjustment must be corrected through established data correction channels to

avoid future manual adjustment.

(3)Any outages due to natural disasters (e.g., 1972 Agnes Flood), which the GeneratorUnavailability Subcommittee determines to have a low probability of recurrence, can be

eliminated from the outage history when calculating outage rates for use in forecasting.

These special events are recorded in the GORP modification file.

(4)A units forced outage rate may be discounted to reflect an official capacity deratingprovided the following conditions are met:

(a)The derating caused the termination of a forced partial reduction which reflected theunits reduced capability during the period from January 1, 1972 through May 31,

1974 (1).

(b)Formal documentation of the derating adjustment must be presented to the GeneratorUnavailability Subcommittee no later than one month prior to the rate publication

deadline.

(c)The derating adjustment must be approved by a majority of the GeneratorUnavailability Subcommittee members.

(d)The derating adjustment must be documented in the rate publication.


35/39





The rate discounting is accomplished by deleting the reported forced partial outage time from

the Outage Data History File and subtracting the forced partial reduction capacity from any net

maximum dependable capacity that was reported concurrently with the reduction (2).

(5)The annual unit EFORDwill be 100% for any period of operation after 1992 during which

minimum reporting requirements are not met. Minimum reporting requirements are definedas either GADS event data or actual hourly net generation for units less than 10 MW. Table

III values for EFORDwill be used for all years prior to the first full year of operation and for

all non-reported years prior to 1992.

Companies that are unable to comply with the minimum reporting requirements after 1992 have

the option to appeal to the Planning Committee for an alternative to the 100% EFORDruling.

(*)These rules were formulated by the Generator Unavailability Subcommittee, approved by the

PJM Planning and Engineering Committee at its November, 1974 (172nd) meeting, and

published in the December, 1974 GUS report to P&E titled "Forced Outage Rates and

Unavailable Capability Due to Planned and Maintenance Outages for the PJM Supplemental

Agreement."

(1) It would not be feasible to adjust for deratings prior to this period due to less stringent data

reporting requirements that were in effect. Adjustments for deratings occurring subsequent to

this period are not legitimate. The PJM contract contains provisions to rerate units within a

reasonable time. During periods where a unit is overrated and a forced partial reduction is

reported, the higher capacity tends to compensate for the increased forced outage rate and future

forecast capacity obligation. Thus, an adjustment for the partial reduction in the outage history

would provide a redundant credit.

(2) An example of a unit satisfying condition 4a. The reported maximum net dependable

capacity of this unit for the period 1/1/72 through 5/31/74 was 132MW. For the entire 29-

month period, the unit had a 5MW forced capacity reduction. The unit was derated 5MW

effective 6/1/74. In compliance with these rules, the 5MW forced reduction was deleted from

the PJM Outage History File and the net maximum dependable capacity was changed to

127MW (132MW minus 5MW) for use in determining the equivalent outage hours.


36/39





Item E: Capacity Variance Calculation Procedure for Existing Units

The capacity variance is one of the inputs to the GEBGE program which is used to determine

the PJM capacity reserve requirement. Theoretically, the capacity variance of a unit is

calculated using the equations

=

=n

1ii

P*i

(C )

C*i

D-(1iC )=

and

=

=n

1ii

P*-i

(C 2)2

where:

MW,mean,=

states,ofnumbern=

MW,i,stateatavailablecapacityCi=

unit-peri,statefor)rateoutagethe(i.e.,inbeingofyprobabilitPi=

i,stateatderationcapacityunit-peri

D =

andMW,capacity,installedsummernetC=

22(MW)variance,=

However, to utilize the information readily available in the outage statistics, a somewhat

modified approach has been taken. For PJM reliability calculations, the effective equivalent

demand forced outage rate represents the mean per-unit unavailability. Therefore, the mean

capacity can be expressed as

C*D

EEFOR-(1 )=

Since the EEFOR includes 25% of the equivalent maintenance outage time, it is a measure ofthe units unavailability due to all unplanned outages. Therefore, the partial outage state

probabilities must be based on the total unplanned outage time spent in each state. A

maintenance f-factor has been introduced to transform the maintenance outage time from a

period hour to a demand hour basis so it can be added to the forced outage time. The

maintenance f-factor, which also included the 25% proportioning, is defined as


37/39





PH*4

DH

PH*4

FOH*f

fSH

m

f =+

=

Th total forced and maintenance outage time spent in each state is:

* MOHfFOH*fHout)(100%stateoutforced100% mf100 +=

imipi * MPOHfFPOH*fHout)(i%stateoutforcedpartial +=

= i1000 H-H-DHHout)(0%stateavailable100%The probability of being in each state is simply the ratio of the time spent in each state to the

total time, or

DH

0HP =

0

DH

100HP =

100

DH

iH

i

P =

The individual state variances can now be calculated using the equation

( )=

=100

ii

P*-C*i

D-

0

2)1(

2

where:

i,stateoflityunavailabiaverageunit-peri

D =

MW,capacity,installedsummernetunitC=

EEFORsunittheusingcalculatedMW,capacity,mean=

istateinbeingofyprobabilitunit-perPi=

This procedure has been incorporated into the Generator Outage Rate Program (GORP) and is

used to produce the information displayed in the "Unit Variance and Partial Outage State

Report."

Future Unit Variance


38/39





Variance values for future fossil and nuclear units were determined by examining the historical

statistics for each unit type. A scatter diagram of the unit equivalent forced capacity Cfwas

plotted against the square root of variance to yield the following equations:

Fossil Steam Unit Variance

( ) 40C*1.1V fF +=5.

OR

( )240C*1.1V fF +=

Nuclear Unit Variance

( ) 140C*0.8V fN +=5.

OR

( )2140C*0.8V fN +=

where:

varianceunitfossilVF=

varianceunitnuclearVN=

df EEFORunitXcapacityunitC =

Variance values for future internal combustion, combined cycle and hydro units were

determined using the standard two-state model calculation:

Internal Combustion, Combined Cycle and Hydro Unit Variance

( ) 2dd C*EEFOR*EEFOR-1V=

where:

VarianceUnitV=

CapacityUnitC=


39/39



PJM Interconnection L L C 5-12

Item F: Generator Unavailability Subcommittee Programs

The Planning Study Outage Data Report and rolling twelve-month EFORdvalues used for the

determination of the unforced capacity factors for all units transacted within the eCapacity

system both utilize the Generator Outage Rate Program (GORP). This program is part of a web-based data collection and processing system referred to as the eGADS system. The equations

shown in Section 3 of this manual are all within the GORP program. Authorized users of the

eGADS system can enter data and run the GORP routines themselves to review the reliability

of their own equipment. They can not use the routines to access any other partys data.

Download - PJM Manual for Generator Unavailability Subcommitte Reference

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