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PJM Manual for
Generator Unavailability Subcommittee
Reference Manual
Manual M22
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
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Generator Unavailability Subcommittee Reference Manual
Table of Contents
Revision History
Approval ......................................................................................................................REV1
Revision History .......................................................................................................... REV1
Introduction
About PJM Manuals..................................................................................................... INT1
About This Manual ....................................................................................................... INT2
Target Users............................................................................................................. INT2
References................................................................................................................ INT3
Using This Manual ....................................................................................................... INT4
What Youll Find In This Manual ........................................................................... INT4
Section 1: Scope of Responsibility
Generator Unavailability Subcommittee .......................................................................... 11
Section 2: Acronyms
Acronym Listing.................................................................................................................21
Section 3: Definitions and Equations
Definitions .........................................................................................................................31
Equations..........................................................................................................................34
Section 4: Periodic Reports
Introduction .......................................................................................................................41
Planning Study Outage Data Report.................................................................................41

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Table of Contents
PJM Interconnection, L.L.C. ii
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Data for Units with Five Full Calendar Years of Operating Experience......................42
Data for Units with Less Than Five Full Calendar Years of Operating Experience and
Future Units ..................................................................................................................43
Class Average Outage Rates .............................................................................................46
Section 5: Miscellaneous Documentation
Item A: Full fFactor Derivation .....................................................................................51
Item B: Partial fFactor Derivation .................................................................................54
Item C: Modified TwoState Model for Reliability Calculations .....................................55
Item D: Rules for Consistency of Generator Outage Rate Calculations..........................57
Item E: Capacity Variance Calculation Procedure for Existing Units ............................59
Item F: Generator Unavailability Subcommittee Programs ..........................................512
Exhibit I.1: List of PJM Manuals..................................................................................... INT1
Exhibit 4.1: Class Average Outage Rates .............................................................................46
Exhibit 5.1: Generator States ................................................................................................51
Exhibit 5.2: Partial fFactor Time Period.............................................................................. 54

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PJM Interconnection, L.L.C REV1
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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
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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  PreScheduling 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  AccountedFor Obligation
M33  Administrative Services for the PJM Inter
connection Agreement
M31  Customer Choice
M29 Billing
M28 Operating Agreement Accounting
M27Open Access Transmission Tariff Accounting
Exhibit I.1: List of PJM Manuals

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Introduction
PJM Interconnection, L.L.C. INT2
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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 3: Definitions and Equations
Section 4:Periodic Reports
Section 5: Miscellaneous Documentation
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 accountedfor input data.

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Introduction
PJM Interconnection, L.L.C. INT3
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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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Introduction
PJM Interconnection, L.L.C. INT4
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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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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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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
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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
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UOH  Unplanned Outage Hours
fp  partial ffactor
ff  full ffactor

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Section 3: Definitions and Equations
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.
Noncurtailing 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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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 34.)
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 34.)
Equivalent Forced Outage Factor: The portion of time a unit is unavailable due to forced outages.
(Refer to Equation 3, page 34.)
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 35.)
Equivalent Planned Outage Factor: The portion of time a unit is unavailable due to planned
outages. (Refer to Equation 5, page 35.)
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 35.)
Effective Equivalent Demand Forced Outage Rate: The forced outage rate used for reliability and
reserve margin calculations. (Refer to Equation 8, page 35.)
Equivalent Scheduled Outage Factor: The planned outage rate used for reliability and reserve
margin calculations. (Refer to Equation 9, page 36.)
Variance: A measure of the variability of a units partial forced outages which is used in reserve
margin calculations.
ffactor: 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 36.)
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 nonequipment 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*
where n is the number of years of accumulated outage hours.
(5)Equivalent Planned Outage Factor:
=
=
+==
168*n
PH
PH
EPOHyearweeksEPOF
or
POHEPOHEPPOHNote
PH
EPPOHPOH
PH
EPOH(%)EPOF
*)/(
:
%100*%100*
where n is the number of years of accumulated outage hours.
(6)Equivalent Planned Outage Extension Factor:
=excluded)(w/SEEPOF
included)(w/SEEPOFEPOEF
(7)Equivalent Availability Factor:
%100*
++=
PH
EPPOH)EMPOH(EFPOHAH(%)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 57 (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) ffactors:(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 ffactor 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 ffactor.

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(3) The current definition of the partial ffactor 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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Section 4: Periodic Reports
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
offpeak outages).
Future capacity additions, deletions and modifications are based on data as provided for
inclusion in the most recent EIA411/860 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 nonreported 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 ffactor). 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.
(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 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
fiveyear 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
nonreported 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 classaverage
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 classaverage 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
mature operating history unless granted an exception.
(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.
(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 following variance formula until the combined cycle unit has
mature operating history unless granted an exception.
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) TenYear 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 tenyear 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 classaverage 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

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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.

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Section 5: Miscellaneous Documentation
Item A: Full fFactor 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 FourState 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
618627.
Reserve
Shutdown
State 0
Forced Out
&
Not Needed
State 1
On Line
State 2
Forced Out
&
Needed
State 3
(1PS) / T
1 / D
PS/ T
1 / T
1 / D
1 / r
1 / r
1 / m

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Terms:
durationoutageforcedaverager =
runtounittheforcallsbetweentimeaverageT =
demandofperiodsduringtimerunaverageD =
outagesforcedbetweentimerunaveragem =
runtocalledisunitthewhenfailurestartaofyprobabilitS
P =
On page 621 of the referenced IEEE paper, the ffactor 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 ffactor 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
+=

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from which we can see that the ffactor 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 ffactor 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 ffactor 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
ffactor (ff) because it is used to weight the full forced outage hours.

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Item B: Partial fFactor Derivation
Exhibit 5.2: Partial fFactor Time Period
The partial ffactor is a measure of the equivalent full forced outage hours that occur during
times of demand. Theoretically, the partial ffactor 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 ffactor 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 ffactor 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

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Item C: Modified TwoState Model for Reliability Calculations
The standard twostate model of a generator considers the unit as being either fully available or
fully unavailable. The modified twostate 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 twostate 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 twostate model calculates the mean available capacity as
C*)D
EEFOR1(=
where:
MWcapacity,mean
=
andMW,capacity,installedsummernetsunitC =
unitperrate,outageforceddemandequivalenteffectivesunitD
EEFOR =
The implied capacity variance about the mean with the standard twostate model is
2C*
DEEFOR*)
DEEFOR1(=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 twostate model preserves both the mean and the variance of the original forced
outage distribution by simultaneously solving the twostate mean and variance equations for
unit capacity and effective equivalent demand forced outage rate using the twostate mean and
variance values. The resulting modified twostate equations are:
DEEFOR1
C
=
and

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2
2
2
DEEFOR
+=
where:
andMW,capacity,netunitstatetwomodifiedC =
unitperD
EEFORstatetwomodifiedD
EEFOR = ,

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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.

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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 nonreported 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.

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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=
unitperi,statefor)rateoutagethe(i.e.,inbeingofyprobabilitPi=
i,stateatderationcapacityunitperi
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 perunit 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 ffactor 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 ffactor, which also included the 25% proportioning, is defined as

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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 HHDHHout)(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,stateoflityunavailabiaverageunitperi
D =
MW,capacity,installedsummernetunitC=
EEFORsunittheusingcalculatedMW,capacity,mean=
istateinbeingofyprobabilitunitperPi=
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

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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 twostate model calculation:
Internal Combustion, Combined Cycle and Hydro Unit Variance
( ) 2dd C*EEFOR*EEFOR1V=
where:
VarianceUnitV=
CapacityUnitC=

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Item F: Generator Unavailability Subcommittee Programs
The Planning Study Outage Data Report and rolling twelvemonth 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 webbased 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.