PSS®E 34.1.

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DATA FORMATS REFERENCE MANUAL

POWER FLOW, SEQUENCE, AND OPTIMAL POWER FLOW DATA

FORMATS

September 2016

Siemens Industry, Inc.

Siemens Power Technologies International
400 State Street, PO Box 1058
Schenectady, NY 12301-1058 USA
+1 518-395-5000
www.siemens.com/power-technologies
 Table of Contents

Chapter 1 - Power Flow Data Contents

1.1 Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-1
1.2 Extended Bus Names . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-1
1.3 Default Values . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-2
1.4 Q Record . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-2
1.5 Case Identification Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-5
1.6 System-Wide Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-6
1.7 Bus Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-9
1.8 Load Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-10
1.9 Fixed Bus Shunt Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-13
1.10 Generator Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-14
1.11 Non-Transformer Branch Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-19
1.12 System Switching Device Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-23
1.13 Transformer Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-24
1.14 Areas, Zones and Owners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-42
1.15 Area Interchange Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-44
1.16 Two-Terminal DC Transmission Line Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-45
1.17 Voltage Source Converter (VSC) DC Transmission Line Data . . . . . . . . . . . . . . . . .1-48
1.18 Transformer Impedance Correction Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-50
1.19 Multi-Terminal DC Transmission Line Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-52
1.20 Multi-Section Line Grouping Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-57
1.21 Zone Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-59
1.22 Interarea Transfer Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-59
1.23 Owner Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-60
1.24 FACTS Device Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-61
1.25 Switched Shunt Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-64
1.26 GNE Device Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-69
1.27 Induction Machine Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-70
1.28 Substation Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-74
1.28.1 Substation Data Record .............................................................................1-74

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 1.28.2 Node Data ..................................................................................................1-75
1.28.3 Station Switching Device Data ...................................................................1-75
1.28.4 Equipment Terminal Data ...........................................................................1-76
1.29 End of Data Indicator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-78

Chapter 2 - Sequence Data File Contents

2.1 Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-1
2.2 Change Code . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-2
2.3 System Wide Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-3
2.4 Generator Sequence Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-4
2.5 Load Sequence Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-6
2.6 Zero Sequence Non-Transformer Branch Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-7
2.7 Zero Sequence Mutual Impedance Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-8
2.8 Zero Sequence Transformer Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-10
2.9 Zero Sequence Switched Shunt Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-17
2.10 Zero Sequence Fixed Shunt Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-18
2.11 Induction Machine Sequence Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-18
2.12 Non-Conventional Source Fault Contribution Data . . . . . . . . . . . . . . . . . . . . . . . . . 2-20

Chapter 3 - Optimal Power Flow Data Contents

3.1 Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-1
3.2 Change Code . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-2
3.3 Bus Voltage Constraint Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-3
3.4 Adjustable Bus Shunt Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-4
3.5 Bus Load Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-6
3.6 Adjustable Bus Load Table Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-7
3.7 Generator Dispatch Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-8
3.8 Active Power Dispatch Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-9
3.9 Generation Reserve Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-10
3.10 Generation Reactive Capability Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-11
3.11 Adjustable Branch Reactance Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-12
3.12 Piece-wise Linear Cost Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-14
3.13 Piece-wise Quadratic Cost Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-15
3.14 Polynomial and Exponential Cost Table . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-17
3.15 Period Reserve Constraint Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-18
3.16 Branch Flow Constraint Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-20
3.17 Interface Flow Constraint Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-22

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 3.18 Linear Constraint Dependency Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-24

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 Chapter 1
Power Flow Data Contents

Chapter 1 - Power Flow Data Contents

1.1 Overview
The input stream to activity READ consists of 23 groups of records, with each group containing a
particular type of data required in power flow work (refer to Figure 1-1). The end of each category
of data, except the Case Identification Data, is indicated by a record specifying a value of zero; the
end of the system-wide, FACTS device, DC line, and GNE device data categories may alternatively
be indicated with a record specifying a NAME value with blanks.The optimal power flow problem
typically consists of several components: one or more objectives, a set of available system controls
and any number of system constraints. The purpose of this chapter is to present the available con-
trols and constraints for the optimal power flow problem statement.

The sections within this chapter are presented in the order in which the data categories must appear
within the OPF Raw Data File. The format of the OPF Raw Data File itself is outlined in Figure 3-1.
Each section of this chapter fully describes the data elements associated with each data model.
Specific information on the use of the data input facilities can be found in Section 14.8 Data Input
and Storage.

1.2 Extended Bus Names

On its Bus Data record, each bus is assigned a bus number and a 12 character alphanumeric name.
When the bus names input option of activity READ is enabled, data fields designating buses on
load, fixed shunt, generator, non-transformer branch, transformer, area, two-terminal dc line, VSC
dc line, multi-terminal dc line, multi-section line, FACTS device, switched shunt, GNE device, and
induction machine, data records may be specified as either extended bus names enclosed in single
quotes or as bus numbers.

The requirements for specifying an extended bus name are:

• The extended name of a bus is a concatenation of its 12 character alphanumeric name

and its Breaker and Switch base voltage.
• It must be enclosed in single quotes.
• The 12 character bus name, including any trailing blanks, must be the first 12 charac-
ters of the extended bus name.
• The bus base voltage in kV follows the 12 character bus name. Up to 6 characters may
be used.

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 Power Flow Data Contents PSS®E 34.1
Default Values Program Operation Manual

• For those data fields for which a sign is used to indicate a modeling attribute, a minus
sign may be specified between the leading single quote and the first character of the
12 character bus name.
Thus, valid forms of an extended bus name include 'aaaaaaaaaaaavvvvvv' and
'aaaaaaaaaaaavvv'. For those data fields cited in (4) above, '-aaaaaaaaaaaavvvvvv' and
'-aaaaaaaaaaaavvv' are also valid forms of extended bus names.

As an example, consider a 345 kV bus with the name ERIE BLVD. The following are all valid forms
of Its extended bus name:

’ERIE BLVD 345.0’

’ERIE BLVD 345’
’ERIE BLVD 345’
The following is not a valid form of its extended bus name because the three tailing blanks of its bus
name are not all included before the base voltage:

’ERIE BLVD 345’

1.3 Default Values

All data is read in free format with data items separated by a comma or one or more blanks; [Tab]
delimited data items are not recommended.

Because there are default values for many of the data items specified in the Power Flow Raw Data
File, you can include only the specific information you need. For example, if bus 99 is a 345 kV Type
1 bus assigned to zone 3, the Bus Data record in the file could be:

99,,345,,,3
This is equivalent to specifying the data record:

99,’ ’,345.0,1,1,3,1,1.0,0.0
If, in addition, you name the bus ERIE BLVD, the minimum data line would be:

99,’ERIE BLVD’,345,,,3

1.4 Q Record
Generally, specifying a data record with a Q in column one is used to indicate that no more data
records are to be supplied to activity READ. This end of data input indicator is permitted anywhere
in the Power Flow Raw Data File except where activity READ is expecting one of the following:

• one of the three Case Identification Data records.

• the second or subsequent records of the four-record block defining a two-winding
transformer.
• the second or subsequent records of the five-record block defining a three-winding
transformer.
• the second or third record of the three-record block defining a two-terminal dc transmis-
sion line.

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Program Operation Manual Q Record

• the second or third record of the three-record block defining a VSC dc transmission
line.
• the second or subsequent records of the series of data records defining a multi-terminal
dc transmission line.
• the second or subsequent records of the series of data records defining a GNE device.

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 Power Flow Data Contents PSS®E 34.1
Q Record Program Operation Manual

Case Identification Data

System-Wide Data

Bus Data

Load Data

Fixed Bus Shunt Data

Generator Data

Non-Transformer Branch Data

System Switching Device Data

Transformer Data

Area Interchange Data

Two-Terminal DC Transmission Line Data

Voltage Source Converter (VSC) DC Transmission Line Data

Transformer Impedance Correction Tables

Multi-Terminal DC Transmission Line Data

Multi-Section Line Grouping Data

Zone Data

Interarea Transfer Data

Owner Data

FACTS Device Data

Switched Shunt Data

GNE Device Data

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 PSS®E 34.1 Power Flow Data Contents
Program Operation Manual Case Identification Data

Induction Machine Data

Substation Data

Q Record

Figure 1-1. Power Flow Raw Data Input Structure

Each substation block data consists of following records.

Substation Data Record

Node Data

Station Switching Device Data

Equipment Terminal Data

1.5 Case Identification Data

Case identification data consists of three data records. The first record contains six items of data as
follows:

IC, SBASE, REV, XFRRAT, NXFRAT, BASFRQ

where:

IC New Case Flag Sequence Data Input Structure:

0for base case input (i.e., clear the working case before adding data to it)
1to add data to the working case
IC = 0 by default.
SBASE System MVA base. SBASE = 100.0 by default.
REV PSS®E revision number. REV = current revision (33) by default.
XFRRAT Units of transformer ratings (refer to Transformer Data). The transformer percent
loading units program option setting (refer to Saved Case Specific Option Settings) is
set according to this data value.
XFRRAT < 0 for MVA
XFRRAT > 0 for current expressed as MVA
XFRRAT = present transformer percent loading program option setting by default
(refer to activity OPTN).

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System-Wide Data Program Operation Manual

NXFRAT Units of ratings of non-transformer branches (refer to Non-Transformer Branch

Data ). The non-transformer branch percent loading units program option setting
(refer to Saved Case Specific Option Settings) is set according to this data value.
NXFRAT < 0 for MVA
NXFRAT > 0 for current expressed as MVA
NXFRAT = present non-transformer branch percent loading program option setting
by default (refer to activity OPTN).
BASFRQ System base frequency in Hertz. The base frequency program option setting (refer to
Saved Case Specific Option Settings) is set to this data value. BASFRQ = present
base frequency program option setting value by default (refer to activity OPTN).

When current ratings are being specified, ratings are entered as:

MVArated =  3 x Ebase x Irated x 10-6

where:

Ebase Is the branch or transformer winding voltage base in volts.

Irated Is the rated phase current in amps.

The next two records each contain a line of text to be associated with the case as its case title. Each
line may contain up to 60 characters, which are entered in columns 1 through 60.

1.6 System-Wide Data

Through the system-wide data category, data that pertains to the case as a whole (rather than to
individual equipment items) may be included in the Power Flow Raw Data File to allow convenient
transfer of it with the case. Records may be included that define:

• power flow solution parameters.

• descriptions of rating sets.
• information on the most recent power flow solution attempt.
Generally, each record specified in the System-Wide Data category begins with a NAME that
defines the type of data specified on the record. The formats of the various records are described
in the following paragraphs.

GENERAL Record
The GENRAL record begins with the name GENERAL and contains solution parameters used by
all of the power flow solution methods. Using keyword input, any or all of the following solution
parameters may be specified:

• THRSHZ (the zero impedance line threshold tolerance)

• PQBRAK (the constant power load characteristic voltage breakpoint)
• BLOWUP (the largest voltage change threshold)
Those solution parameters that are specified may be entered in any order. The following is an
example of the GENERAL record:

GENERAL, THRSHZ=0.0001, PQBRAK=0.7, BLOWUP=5.0

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Program Operation Manual System-Wide Data

GAUSS Record
The GAUSS record begins with the name GAUSS and contains solution parameters used by the
Gauss-Seidel power flow solution methods (SOLV and MSLV). Using keyword input, any or all of
the following solution parameters may be specified:

• ITMX (the maximum number of iterations)

• ACCP (real component voltage change acceleration factor)
• ACCQ (imaginary component voltage change acceleration factor)
• ACCM (type 1 bus complex voltage change acceleration factor in MSLV)
• TOL (voltage magnitude change convergence tolerance)
Those solution parameters that are specified may be entered in any order. The following is an
example of the GAUSS record:

GAUSS, ITMX=100, ACCP=1.6, ACCQ=1.6, ACCM=1.0, TOL=0.0001

NEWTON Record
The NEWTON record begins with the name NEWTON and contains solution parameters used by
the Newton-Raphson power flow solution methods (FDNS, FNSL and NSOL). Using keyword input,
any or all of the following solution parameters may be specified:

• ITMXN (the maximum number of iterations)

• ACCN (voltage magnitude setpoint change acceleration factor at voltage controlled
buses)
• TOLN (mismatch convergence tolerance)
• VCTOLQ (controlled bus reactive power mismatch convergence tolerance)
• VCTOLV (controlled bus voltage error convergence tolerance)
• DVLIM (maximum votlage magnitude change that may be applied on any iteration)
• NDVFCT (non-divergent solution improvement factor)
Those solution parameters that are specified may be entered in any order. The following is an
example of the NEWTON record:

NEWTON, ITMXN=20, ACCN=1.0, TOLN=0.1, VCTOLQ=0.1, VCTOLV=0.00001, DVLIM=0.99, NDVFCT=0.99

ADJUST Record
The ADJUST record begins with the name ADJUST and contains solution parameters used by the
automatic adjustment functions of the Gauss-Seidel and Newton-Raphson power flow solution
methods. Using keyword input, any or all of the following solution parameters may be specified:

• ADJTHR (automatic adjustment threshold tolerance)

• ACCTAP (tap movement deceleration factor)
• TAPLIM (maximum tap ratio change on any iteration)
• SWVBND (percent of voltage band switched shunts with voltage violations that are
adjusted on any iteration)
• MXTPSS (maximum number of tap and/or switched shunt adjustment cycles)
• MXSWIM (maximum number of induction machine state switchings)
Those solution parameters that are specified may be entered in any order. The following is an
example of the ADJUST record:

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ADJUST, ADJTHR=0.005, ACCTAP=1.0, TAPLIM=0.05, SWVBND=100.0, MXTPSS=99, MXSWIM=10

TYSL Record
The TYSL record begins with the name TYSL and contains solution parameters used by the bal-
anced switching network solution (TYSL). Using keyword input, any or all of the following solution
parameters may be specified:

• ITMXTY (the maximum number of iterations)

• ACCTY (voltage change acceleration factor)
• TOLTY (voltage magnitude change convergence tolerance)
Those solution parameters that are specified may be entered in any order. The following is an
example of the TYSL record:

TYSL, ITMXTY=20, ACCTY=1.0, TOLTY=0.00001

SOLVER Record
The SOLVER record begins with the name SOLVER and identifies the power flow solution method
and solution options used in the last power flow solution attempt.

Following the name SOLVER is the name of the solution method (either FDNS, FNSL, NSOL, SOLV
or MSLV). Then, using keyword input, any or all of the following solution option selections may be
specified:

• ACTAPS (the ac tap adjustment code)

• AREAIN (the area interchange adjustment code)
• PHSHFT (the phase shift adjustment code)
• DCTAPS (the dc tap adjustment code)
• SWSHNT (the switched shunt adjustment code)
• FLATST (the flat start code)
• VARLIM (the reactive power limit application code)
• NONDIV (the non-divergent solution code)
Those solution options that are specified may be entered in any order. The following is an example
of the SOLVER record:

SOLVER, FNSL, ACTAPS=1, AREAIN=0, PHSHFT=0, DCTAPS=1, SWSHNT=1, FLATST=0, VARLIM=0, NONDIV=0

RATING Record
The RATING record begins with the name RATING and specifies a six-character name and a 32-
character description associated with a specified rating set.

Following the name RATING are the following data items:

• the number of the rating set (1 through 12),

• a quoted string that contains the rating’s name (this is used as a column heading in sev-
eral reports), and
• a quoted string that contains the rating’s description.
If no RATING record is specified for rating set "n", its name is set to "RATEn" and its description is
set to "RATING SET n".

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 PSS®E 34.1 Power Flow Data Contents
Program Operation Manual Bus Data

The following is an example of the RATING record:

RATING, 3, "STEMER", "Short term summer emergency"

System wide data input is terminated with a record specifying a value of zero.

1.7 Bus Data

Each network bus to be represented in PSS®E is introduced by reading a bus data record. Each
bus data record has the following format:

I, 'NAME', BASKV, IDE, AREA, ZONE, OWNER, VM, VA, NVHI, NVLO, EVHI, EVLO

where:

I Bus number (1 through 999997). No default allowed.

NAME Alphanumeric identifier assigned to bus I. NAME may be up to twelve characters
and may contain any combination of blanks, uppercase letters, numbers and
special characters, but the first character must not be a minus sign. NAME must
be enclosed in single or double quotes if it contains any blanks or special char-
acters. NAME is twelve blanks by default.
BASKV Bus base voltage; entered in kV. BASKV = 0.0 by default.
IDE Bus type code:
1 for a load bus or passive node (no generator boundary condition) 
2 for a generator or plant bus (either voltage regulating or fixed Mvar) 
3 for a swing bus 
4 for a disconnected (isolated) bus
IDE = 1 by default.
AREA Area number (1 through 9999). AREA = 1 by default.
ZONE Zone number (1 through 9999). ZONE = 1 by default.
OWNER Owner number (1 through 9999). OWNER = 1 by default.
VM Bus voltage magnitude; entered in pu. VM = 1.0 by default.
VA Bus voltage phase angle; entered in degrees. VA = 0.0 by default.
NVHI Normal voltage magnitude high limit; entered in pu. NVHI=1.1 by default
NVLO Normal voltage magnitude low limit, entered in pu. NVLO=0.9 by default
EVHI Emergency voltage magnitude high limit; entered in pu. EVHI=1.1 by default
EVLO Emergency voltage magnitude low limit; entered in pu. EVLO=0.9 by default

Bus data input is terminated with a record specifying a bus number of zero.

Bus Data Notes

VM and VA need to be set to their actual solved case values only when the network, as entered into
the working case via activity READ, is to be considered solved as read in. Otherwise, unless some
better estimate of the solved voltage and/or phase angle is available, VM and VA may be omitted
(and therefore set to their default values; see Default Values).

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1.8 Load Data

Each network bus at which load is to be represented must be specified in at least one load data
record. Multiple loads may be represented at a bus by specifying more than one load data record
for the bus, each with a different load identifier.

Distributed
Bus “I” Load Generation

Each load at a bus can be a mixture of loads with three different characteristics: the Constant Power
Load Characteristic, the Constant Current Load Characteristic, and the constant admittance load
characteristic. For additional information on load characteristic modeling, refer to Section 6.3.13,
Load, activities CONL and RCNL, Section 12.3.1, Modeling Load Characteristics and Section
12.3.2, Basic Load Characteristics.

Each load data record has the following format:

I, ID, STATUS, AREA, ZONE, PL, QL, IP, IQ, YP, YQ, OWNER, SCALE, INTRPT,
DGENP, DGENQ, DGENM

where:

I Bus number, or extended bus name enclosed in single quotes (refer to Extended Bus
Names). No default allowed.
ID One- or two-character uppercase non-blank alphanumeric load identifier used to
distinguish among multiple loads at bus I. It is recommended that, at buses for which
a single load is present, the load be designated as having the load identifier 1. ID = 1
by default.
STATUS Load status of one for in-service and zero for out-of-service. STATUS = 1 by default.
AREA Area to which the load is assigned (1 through 9999). By default, AREA is the area to
which bus I is assigned (refer to Bus Data).
ZONE Zone to which the load is assigned (1 through 9999). By default, ZONE is the zone to
which bus I is assigned (refer to Bus Data).
PL Active power component of constant MVA load; entered in MW. PL = 0.0 by default.
QL Reactive power component of constant MVA load; entered in Mvar. QL = 0.0 by
default.
IP Active power component of constant current load; entered in MW at one per unit
voltage. IP = 0.0 by default.
IQ Reactive power component of constant current load; entered in Mvar at one per unit
voltage. IQ = 0.0 by default.
YP Active power component of constant admittance load; entered in MW at one per unit
voltage. YP = 0.0 by default.

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YQ Reactive power component of constant admittance load; entered in Mvar at one per
unit voltage. YQ is a negative quantity for an inductive load and positive for a capaci-
tive load. YQ = 0.0 by default.
OWNER Owner to which the load is assigned (1 through 9999). By default, OWNER is the
owner to which bus I is assigned (refer to Bus Data).
SCALE Load scaling flag of one for a scalable load and zero for a fixed load (refer to SCAL).
SCALE = 1 by default.
INTRPT Interruptible load flag of one for an interruptible load for zero for a non interruptible
load. INTRPT=0 by default.
DGENP Distributed Generation active power component; entered in units of MW. DGENP =
0.0 by default.
DGENQ Distributed Generation reactive power component; entered in units of MVAR.
DGENQ = 0.0 by default.
DGENM Distributed Generation operation mode; 0 = distributed generation on feeder is OFF,
1 = distributed generation on feeder is ON. DGENM = 0 by default.

Load data input is terminated with a record specifying a bus number of zero.

Load Data Notes

The area, zone, and owner assignments of loads are used for area, zone, and owner totaling pur-
poses (e.g., in activities AREA, OWNR, and ZONE) and for load scaling and conversion purposes.
They may differ from those of the bus to which they are connected. The area and zone assignments
of loads may optionally be used during area and zone interchange calculations (refer to Area Inter-
change Control and activities AREA, ZONE, TIES, TIEZ, INTA, and INTZ).

Constant Power Load Characteristic

The constant power characteristic holds the load power values, and also, the distributed generation
power values, constant as long as the bus voltage exceeds a value specified by the solution param-
eter PQBRAK. The constant power characteristic assumes an elliptical current-voltage
characteristic of the corresponding load current for voltages below this threshold. Figure 1-2 depicts
this characteristic for PQBRAK values of 0.6, 0.7, and 0.8 pu. The user may modify the value of
PQBRAK using the [Solution Parameters] GUI (refer to PSS®E GUI Users Guide, Section 11.1.1,
Boundary Conditions).

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1.1
1.0
0.0

0.0 0.6 0.7 0.8 1.0 1.1

Voltage

Figure 1-2. Constant Power Load Characteristic

Constant Current Load Characteristic

The constant current characteristic holds the load current constant as long as the bus voltage
exceeds 0.5 pu, and assumes an elliptical current-voltage characteristic as shown in Figure 1-3 for
voltages below 0.5 pu.

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1.1
Current

1.0
Power
0.5
0.0

0.0 0.5 1.0 1.1

Voltage

Figure 1-3. Constant Current Load Characteristic

1.9 Fixed Bus Shunt Data

Each network bus at which fixed bus shunt is to be represented must be specified in at least one
fixed bus shunt data record. Multiple fixed bus shunts may be represented at a bus by specifying
more than one fixed bus shunt data record for the bus, each with a different shunt identifier.

Each fixed bus shunt data record has the following format:

I, ID, STATUS, GL, BL

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where:

I Bus number, or extended bus name enclosed in single quotes (refer to Extended
Bus Names). No default allowed.
ID One- or two-character uppercase non-blank alphanumeric shunt identifier used to
distinguish among multiple shunts at bus I. It is recommended that, at buses for
which a single shunt is present, the shunt be designated as having the shunt identi-
fier 1. ID = 1 by default.
STATUS Shunt status of one for in-service and zero for out-of-service. STATUS = 1 by
default.
GL Active component of shunt admittance to ground; entered in MW at one per unit
voltage. GL should not include any resistive impedance load, which is entered as
part of load data. GL = 0.0 by default.
BL Reactive component of shunt admittance to ground; entered in Mvar at one per unit
voltage. BL should not include any reactive impedance load, which is entered as
part of load data; line charging and line connected shunts, which are entered as part
of non-transformer branch data; transformer magnetizing admittance, which is
entered as part of transformer data; or switched shunt admittance, which is entered
as part of switched shunt data. BL is positive for a capacitor, and negative for a
reactor or an inductive load. BL = 0.0 by default.

Fixed bus shunt data input is terminated with a record specifying a bus number of zero.

Fixed Shunt Data Notes

The area, zone, and owner assignments of the bus to which the shunt is connected are used for
area, zone, and owner totaling purposes (e.g., in activities AREA, OWNR, and ZONE; refer to Sec-
tion 11.7, Summarizing Area Totals through Section 11.12, Summarizing Zone-to-Zone
Interchange) and for shunt scaling purposes (refer to SCAL).

The admittance specified in the data record can represent a shunt capacitor or a shunt reactor (both
with or without a real component) or a shunt resistor. It must not represent line connected admit-
tance, switched shunts, loads, line charging or transformer magnetizing impedance, all of which are
entered in other data categories.

1.10 Generator Data

Each network bus to be represented as a generator or plant bus in PSS®E must be specified in a
generator data record. In particular, each bus specified in the bus data input with a Type code of 2
or 3 must have a generator data record entered for it.

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Each generator has a single line data record with the following format:

I,ID,PG,QG,QT,QB,VS,IREG,MBASE,ZR,ZX,RT,XT,GTAP,STAT,
RMPCT,PT,PB,O1,F1,...,O4,F4,WMOD,WPF

where:

I Bus number, or extended bus name enclosed in single quotes (refer to Extended
Bus Names). No default allowed.
ID One- or two-character uppercase non-blank alphanumeric machine identifier used
to distinguish among multiple machines at bus I. It is recommended that, at buses
for which a single machine is present, the machine be designated as having the
machine identifier 1. ID = 1 by default.
PG Generator active power output; entered in MW. PG = 0.0 by default.
QG Generator reactive power output; entered in Mvar. QG needs to be entered only if
the case, as read in, is to be treated as a solved case. QG = 0.0 by default.
QT Maximum generator reactive power output; entered in Mvar. For fixed output gener-
ators (i.e., nonregulating), QT must be equal to the fixed Mvar output. For infeed
machines (WMOD=4), QT is not used in powerflow calculations. The reactive power
output of infeed machines is held constant at QG. QT = 9999.0 by default.
QB Minimum generator reactive power output; entered in Mvar. For fixed output gener-
ators, QB must be equal to the fixed Mvar output. For infeed machines (WMOD=4),
QB is not used in powerflow calculations. The reactive power output infeed
machines is held QB = -9999.0 by default.
VS Regulated voltage setpoint; entered in pu. VS = 1.0 by default.
IREG Bus number, or extended bus name enclosed in single quotes, of a remote Type 1
or 2 bus for which voltage is to be regulated by this plant to the value specified by
VS. If bus IREG is other than a Type 1 or 2 bus, bus I regulates its own voltage to
the value specified by VS. IREG is entered as zero if the plant is to regulate its own
voltage and must be zero for a Type 3 (swing) bus. IREG = 0 by default.
MBASE Total MVA base of the units represented by this machine; entered in MVA. This
quantity is not needed in normal power flow and equivalent construction work, but is
required for switching studies, fault analysis, and dynamic simulation.
MBASE = system base MVA by default.
ZR,ZX Complex machine impedance, ZSORCE; entered in pu on MBASE base. This data
is not needed in normal power flow and equivalent construction work, but is required
for switching studies, fault analysis, and dynamic simulation. For dynamic simula-
tion, this impedance must be set equal to the unsaturated subtransient impedance
for those generators to be modeled by subtransient level machine models, and to
unsaturated transient impedance for those to be modeled by classical or transient
level models. For short-circuit studies, the saturated subtransient or transient
impedance should be used. ZR = 0.0 and ZX = 1.0 by default.
RT,XT Step-up transformer impedance, XTRAN; entered in pu on MBASE base. XTRAN
should be entered as zero if the step-up transformer is explicitly modeled as a
network branch and bus I is the terminal bus. RT+jXT = 0.0 by default.
GTAP Step-up transformer off-nominal turns ratio; entered in pu on a system base. GTAP
is used only if XTRAN is non-zero. GTAP = 1.0 by default.

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STAT Machine status of one for in-service and zero for out-of-service; STAT = 1 by
default.
RMPCT Percent of the total Mvar required to hold the voltage at the bus controlled by bus I
that are to be contributed by the generation at bus I; RMPCT must be positive.
RMPCT is needed only if IREG specifies a valid remote bus and there is more than
one local or remote voltage controlling device (plant, switched shunt, FACTS device
shunt element, or VSC dc line converter) controlling the voltage at bus IREG to a
setpoint, or IREG is zero but bus I is the controlled bus, local or remote, of one or
more other setpoint mode voltage controlling devices. RMPCT = 100.0 by default.
PT Maximum generator active power output; entered in MW. PT = 9999.0 by default.
PB Minimum generator active power output; entered in MW. PB = -9999.0 by default.
Oi Owner number (1 through 9999). Each machine may have up to four owners. By
default, O1 is the owner to which bus I is assigned (refer to Bus Data) and O2, O3,
and O4 are zero.
Fi Fraction of total ownership assigned to owner Oi; each Fi must be positive. The Fi
values are normalized such that they sum to 1.0 before they are placed in the
working case. By default, each Fi is 1.0.
WMOD Machine control mode; WMOD is used to indicate whether a machine is a conven-
tional or a non-conventional machine (e.g. renewables, infeed) machine, and, if it is,
the type of reactive power limits to be imposed. Non-conventional machines are
renewables (e.g., wind, PV etc.) and infeed machines (for definition of infeed
machines, see description below of WNMOD=4)
0 a conventional machine (e.g. synchronous machines).
1 renewable type machine for which reactive power limits are specified
by QT and QB.
2 renewable type machine for which reactive power limits are determined
from the machine’s active power output and WPF; limits are of equal
magnitude and opposite sign
3 renewable type machine with a fixed reactive power setting determined
from the machine’s active power output and WPF; when WPF is posi-
tive, the machine’s reactive power has the same sign as its active
power; when WPF is negative, the machine’s reactive power has the
opposite sign of its active power.
4 infeed type machine. An infeed type machine is one for which the
machine reactive power (QG) is held constant. The QT and QB limits
values are not used and are for information only. QG value has to be
between QT and QB.
WMOD = 0 by default.
WPF Power factor used in calculating reactive power limits or output when WMOD is 2 or
3. WPF = 1.0 by default.

Generator data input is terminated with a record specifying a bus number of zero.

Reactive Power Limits

In specifying reactive power limits for voltage controlling plants (i.e., those with unequal reactive
power limits), the use of very narrow var limit bands is discouraged. The Newton-Raphson based

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power flow solutions require that the difference between the controlling equipment's high and low
reactive power limits be greater than 0.002 pu for all setpoint mode voltage controlling equipment
(0.2 Mvar on a 100 MVA system base). It is recommended that voltage controlling plants have Mvar
ranges substantially wider than this minimum permissible range.

For additional information on generator modeling in power flow solutions, refer to Section 6.3.12,
Generation and Section 6.3.18, AC Voltage Control.

Modeling of Generator Step-Up Transformers (GSU)

Before setting-up the generator data, it is important to understand the two methods by which a gen-
erator and its associated GSU are represented.

The Implicit Method

• The transformer data is included on the generator data record.

• The transformer is not explicitly represented as a transformer branch.
• The generator terminal bus is not explicitly represented.
Figure 1-4 shows that bus K is the Type 2 bus. This is the bus at which the generator will regu-
late/control voltage unless the user specifies a remote bus.

Figure 1-4. Implicit GSU Configuration – Specified as Part of the Generator

The Explicit Method

In this method, the transformer data is not specified with the generator data. It is entered separately
(see Transformer Data) in a transformer branch data block.

In Figure 1-5, there is an additional bus to represent the generator terminal. This is the Type 2 bus
where the generator will regulate/control voltage unless the user specifies a remote bus.

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Figure 1-5. Explicit GSU Configuration – Specified Separately from the

Generator

Multiple Machine Plants

If a generating plant has several units, they can be represented separately even if they are con-
nected to the same Type 2 bus. When two or more machines are to be separately modeled at a
plant, their data may be introduced into the working case using one of two approaches.

A generator data record may be entered in activities READ, Reading Sequence Data Additions from
the Terminal, or RDCH for each of the machines to be represented, with machine powers, power
limits, impedance data, and step-up transformer data for each machine specified on separate gen-
erator data records. The plant power output and power limits are taken as the sum of the
corresponding quantities of the in-service machines at the plant. The values specified for VS, IREG,
and RMPCT, which are treated as plant quantities rather than individual machine quantities, must
be identical on each of these generator data records.

Alternatively, a single generator record may be specified in activities READ, TREA, or RDCH with
the plant total power output, power limits, voltage setpoint, remotely regulated bus, and percent of
contributed Mvar entered. Impedance and step-up transformer data may be omitted. The PSS®E
power flow activities may be used and then, any time prior to beginning switching study, fault anal-
ysis, or dynamic simulation work, activity MCRE may be used to introduce the individual machine
impedance and step-up transformer data; activity MCRE also apportions the total plant loading
among the individual machines.

As an example, Figure 1-6 shows three Type 2 buses, each having two connected units. For gen-
erators 1 through 4, the GSU is explicitly represented while for generators 5 and 6 the GSU is
implicitly represented. Figure 1-7 shows the generator data records corresponding to Figure 1-6.

The separate transformer data records for the explicitly represented transformers from buses
1238 and 1239 to bus 1237 are not included in Figure 1-7.

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Figure 1-6. Multiple Generators at a Single Plant

(not specified)

I ID PG QG QT QB VS IREG MBASE ZR,ZX RT,XT GTAP STAT RMPCT PT PB

Figure 1-7. Data Set for the Multiple Generators in Figure 1-6

1.11 Non-Transformer Branch Data

Each ac network branch to be represented in PSS®E as a non-transformer branch is introduced by
reading a non-transformer branch data record.

Branches to be modeled as transformers are not specified in this data category; rather, they
are specified in Transformer Data.

When specifying a non-transformer branch between buses I and J with circuit identifier CKT, if a
two-winding transformer between buses I and J with a circuit identifier of CKT is already present in
the working case, it is replaced (i.e., the transformer is deleted from the working case and the newly
specified branch is then added to the working case).

In PSS®E, the basic transmission line model is an Equivalent Pi connected between network buses.
Figure 1-8 shows the required parameter data where the equivalent Pi is comprised of:

• A series impedance (R + jX).

• Two admittance branches (jBch/2) representing the line’s capacitive admittance (line
charging).

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• Two admittance branches (G + jB) for shunt equipment units (e.g., reactors) that are
connected to and switched with the line.
To represent shunts connected to buses, that shunt data should be entered in fixed shunt
and/or switched shunt data records.

Figure 1-8. Transmission Line Equivalent Pi Model

Each non-transformer branch data record has the following format:

I,J,CKT,R,X,B,'NAME',RATE1...RATE12,GI,BI,GJ,BJ,ST,MET,LEN,O1,F1,...,O4,
F4

where:

I Branch from bus number, or extended bus name enclosed in single quotes (refer to
Extended Bus Names). No default allowed.
J Branch to bus number, or extended bus name enclosed in single quotes.
CKT One- or two-character uppercase non-blank alphanumeric branch circuit identifier;
the first character of CKT must not be an ampersand ( & ); refer to Multi-Section
Line Grouping Data. If the first character of CKT is greater than sign (>), the branch
buses I and J belong to the same substation in GIC data (see Section 7.2, GIC Data
File Contents). Unless it is a breaker, switch, or branch in GIC data substation, it is
recommended that single circuit branches be designated as having the circuit iden-
tifier 1. CKT = 1 by default.
R Branch resistance; entered in pu. A value of R must be entered for each branch.
X Branch reactance; entered in pu. A non-zero value of X must be entered for each
branch. Refer to Zero Impedance Lines for details on the treatment of branches as
zero impedance lines.
B Total branch charging susceptance; entered in pu. B = 0.0 by default.
NAME Alphanumeric identifier assigned to the branch. NAME may be up to forty charac-
ters and may contain any combination of blanks, uppercase letters, numbers and
special characters. NAME must be enclosed in single or double quotes if it contains
any blanks or special characters. NAME is blank by default.

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RATEn nth rating; entered in either MVA or current expressed as MVA, according to the
value specified for NXFRAT specified on the first data record (refer to Case Identifi-
cation Data).
Each RATEn = 0.0 (bypass check for this branch; this branch will not be included in
any examination of circuit loading) by default. Refer to activity RATE.
When specified in units of current expressed as MVA, ratings are entered as:

MVArated =  3 x Ebase x Irated x 10-6

where:
Ebaseis the base line-to-line voltage in volts of the buses to which 
the terminal of the branch is connected
Iratedis the branch rated phase current in amperes.
GI,BI Complex admittance of the line shunt at the bus I end of the branch; entered in pu.
BI is negative for a line connected reactor and positive for line connected capacitor.
GI + jBI = 0.0 by default.
GJ,BJ Complex admittance of the line shunt at the bus J end of the branch; entered in pu.
BJ is negative for a line connected reactor nd positive for line connected capacitor.
GJ + jBJ = 0.0 by default.
ST Branch status of one for in-service and zero for out-of-service; ST = 1 by default.
MET Metered end flag;
<1 to designate bus I as the metered end
>2 to designate bus J as the metered end.
MET = 1 by default.
LEN Line length; entered in user-selected units. LEN = 0.0 by default.
Oi Owner number (1 through 9999). Each branch may have up to four owners. By
default, O1 is the owner to which bus I is assigned (refer to Bus Data) and O2, O3,
and O4 are zero.
Fi Fraction of total ownership assigned to owner Oi; each Fi must be positive. The Fi
values are normalized such that they sum to 1.0 before they are placed in the
working case. By default, each Fi is 1.0.

Non-transformer branch data input is terminated with a record specifying a from bus number of
zero.

Zero Impedance Lines

PSS®E provides for the treatment of bus ties, jumpers, breakers, switches, and other low imped-
ance branches as zero impedance lines. For a branch to be treated as a zero impedance line, it
must have the following characteristics:

• Its resistance must be zero.

• Its magnitude of reactance must be less than or equal to the zero impedance line
threshold tolerance, THRSHZ.
• It must be a non-transformer branch.

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During network solutions, buses connected by such lines are treated as the same bus, thus having
identical bus voltages. At the completion of each solution, the loadings on zero impedance lines are
determined.

When obtaining power flow solutions, zero impedance line flows, as calculated at the end of the
solution, are preserved with the working case and are available to the power flow solution reporting
activities. Similarly, in activity SCMU, the positive, negative, and zero sequence branch currents on
zero impedance lines are determined and preserved, and are subsequently available to activity
SCOP. In the ACCC, as well as activity ASCC and in the linearized network analysis activities, zero
impedance line results are calculated and reported as needed.

The remainder of this section contains points to be noted, and restrictions to be observed, in using
zero impedance lines.

Branch impedances may not be specified as identically zero; a non-zero reactance must be speci-
fied for all branches, and those meeting the criteria above are treated as zero impedance lines.

The zero impedance line threshold tolerance, THRSHZ, may be changed using the category of
solution parameter data via activity CHNG or the [Solution Parameters] dialog. Setting THRSHZ to
zero disables zero impedance line modeling, and all branches are represented with their specified
impedances.

A zero impedance line may not have a transformer in parallel with it. Although not required, it is rec-
ommended that no other in-service lines exist in parallel with a zero impedance line.

A zero impedance line may have non-zero values of line charging and/or line connected shunts.
This allows, for example, a low impedance cable to be modeled as a zero impedance line.

When more than two buses are connected together by zero impedance lines in a loop arrangement,
there is no unique solution to the flows on the individual zero impedance lines that form the loop. In
this case, the reactances specified for these branches is used in determining the zero impedance
line flows.

It is important to note that buses connected together by zero impedance lines are treated as a single
bus by the power flow solution activities. Hence, equipment controlling the voltages of multiple
buses in a zero impedance connected group of buses must have coordinated voltage schedules
(i.e., the same voltage setpoint should be specified for each of the voltage controlling devices).
Activity CNTB recognizes this condition in scanning for conflicting voltage objectives, and activity
REGB may be used to generate a regulated bus report.

Similarly, if multiple voltage controlling devices are present in a group of buses connected together
by zero impedance lines, the power flow solution activities handle the boundary condition as if they
are all connected to the same bus (refer to Setpoint Voltage Control).

In fault analysis activities, a branch treated as a zero impedance line in the positive sequence is
treated in the same manner in the zero sequence, regardless of its zero sequence branch imped-
ance. Zero sequence mutual couplings involving a zero impedance line are ignored in the fault
analysis solution activities.

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Program Operation Manual System Switching Device Data

1.12 System Switching Device Data

Breaker and Switch Branches
Breakers and switches can be represented by system switching devices in PSS®E. System
switching devices are set to represent breakers or switches by setting the STYPE data element
described below.

Most activities do not honor the system switching devices. System switching devices are treated as
zero impedance lines if they have characteristics of zero impedance lines; otherwise, they are
treated as regular non-transformer branches.

System switching devices are recognized in Substation Reliability Assessment (refer to Section
6.16, Calculating Substation Reliability) and activity DFAX. Substation Reliability Assessment sim-
ulates operations of breakers to isolate faults in a substation and manual switching to restore the
service to supply loads. Distribution Factor File setup activity can process automatic commands to
operate and monitor breakers and switches in Contingency Description Data File and Monitored
Element Data File respectively.

As mentioned in the section Zero Impedance Lines, PSS®E is able to handle a loop arrangement
consisting of zero impedance lines so that users can build a fully detailed bus/breaker model for any
bus configuration, such as a ring bus configuration. When adding a system switching device into a
network model, connectivity nodes where the terminals of a transmission line connect to the termi-
nals of the system switching device must be added as well. This will change a bus branch
configuration which is widely used in planning studies to a detailed bus breaker configuration and
lead to a tremendous increase in number of buses. In such cases as this, the use of the the use of
the extensive substation modeling capabilities introduced in PSS®E 34 is recommended.

I,J,CKTID,X,RATE1...RATE12,STATUS,NSTATUS,METERED,STYPE,NAME

I From bus number. No default allowed.

J To bus number. No default allowed.
CKTID two-character uppercase non-blank alphanumeric switching device
identifier; CKT = 1 by default.
X Branch reactance; entered in pu, must be less than ZTHRES
RATEn nth rating; entered in either MVA or current expressed as MVA,
according to the value specified for NXFRAT specified on the first data
record (refer to Case Identification Data).
Each RATEn = 0.0 (bypass check for this branch; this branch will not
be included in any examination of circuit loading) by default. Refer to
activity RATE.
STATUS 1 for close, 0 for open
NSTATUS Normal service status, 1 for normally open and 0 for normally close
METERD Metered end
STYPE Switching device type
1 - Generic connector
2 - Circuit breaker
3 - Disconnect switch
NAME System switching device name

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System Switching Device data input is terminated with a record specifying a from bus number of
zero.

1.13 Transformer Data

Each ac transformer to be represented in PSS®E is introduced through transformer data record
blocks that specify all the data required to model transformers in power flow calculations, with one
exception. That exception is an optional set of ancillary data, transformer impedance correction
tables, which define the manner in which transformer impedance changes as off-nominal turns ratio
or phase shift angle is adjusted. Those data records are described in Transformer Impedance Cor-
rection Tables.

Both two-winding and three-winding transformers are specified in transformer data record blocks.
Two-winding transformers require a block of four data records. Three-winding transformers require
five data records.

t = t1 / t2; transformer turns ratio

t1: winding 1 turns ratio in kV or pu on bus voltage base or winding

voltage base

t2: winding 2 turns ratio in kV or pu on bus voltage base or winding

voltage base

Figure 1-9 shows the transformer winding configurations.

t1 t2
t1 : t2

t3

Figure 1-9. Two and Three-winding Transformer Configurations Related to

Data Records

The five record transformer data block for three-winding transformers has the following format:

I,J,K,CKT,CW,CZ,CM,MAG1,MAG2,NMETR,’NAME’,STAT,O1,F1,...,O4,F4,VECGRP,ZCOD
R1-2,X1-2,SBASE1-2,R2-3,X2-3,SBASE2-3,R3-1,X3-1,SBASE3-1,VMSTAR,ANSTAR

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Program Operation Manual Transformer Data

WINDV1,NOMV1,ANG1,RATE11...RATE121,COD1,CONT1,RMA1,RMI1,VMA1,VMI1,NTP1,TAB1,CR1,CX1,CNXA1
WINDV2,NOMV2,ANG2,RATE12...RATE122,COD2,CONT2,RMA2,RMI2,VMA2,VMI2,NTP2,TAB2,CR2,CX2,CNXA2
WINDV3,NOMV3,ANG3,RATE13...RATE123,COD3,CONT3,RMA3,RMI3,VMA3,VMI3,NTP3,TAB3,CR3,CX3,CNXA3

The four-record transformer data block for two-winding transformers is a subset of the data required
for three-winding transformers and has the following format:

I,J,K,CKT,CW,CZ,CM,MAG1,MAG2,NMETR,’NAME’,STAT,O1,F1,...,O4,F4,VECGRP
R1-2,X1-2,SBASE1-2
WINDV1,NOMV1,ANG1,RATE11...RATE121,COD1,CONT1,RMA1,RMI1,VMA1,VMI1,NTP1,TAB1,CR1,CX1,CNXA1
WINDV2,NOMV2

Control parameters for the automatic adjustment of transformers and phase shifters are specified
on the third record of the two-winding transformer data block, and on the third through fifth records
of the three-winding transformer data block. All transformers are adjustable and the control param-
eters may be specified either at the time of raw data input or subsequently via activity CHNG or the
transformer [Spreadsheets]. Any two-winding transformer and any three-winding transformer winding
for which no control data is provided has default data assigned to it; the default data is such that the
two-winding transformer or three-winding transformer winding is treated as locked.

Refer to Transformer Sequence Numbers and Three-Winding Transformer Notes for additional
details on the three-winding transformer model used in PSS®E.

When specifying a two-winding transformer between buses I and J with circuit identifier CKT, if a
nontransformer branch between buses I and J with a circuit identifier of CKT is already present in
the working case, it is replaced (i.e., the nontransformer branch is deleted from the working case
and the newly specified two-winding transformer is then added to the working case).

All data items on the first record are specified for both two- and three-winding transformers except
for ZCOD, which is specified only for three-winding transformers

I The bus number, or extended bus name enclosed in single quotes (refer to
Extended Bus Names), of the bus to which Winding 1 is connected. The trans-
former’s magnetizing admittance is modeled on Winding 1. Winding 1 is the only
winding of a two-winding transformer for which tap ratio or phase shift angle may be
adjusted by the power flow solution activities; any winding(s) of a three-winding
transformer may be adjusted. No default is allowed.
J The bus number, or extended bus name enclosed in single quotes, of the bus to
which Winding 2 is connected. No default is allowed.
K The bus number, or extended bus name enclosed in single quotes, of the bus to
which Winding 3 is connected. Zero is used to indicate that no third winding is
present (i.e., that a two-winding rather than a three-winding transformer is being
specified). K = 0 by default.
CKT One- or two-character uppercase non-blank alphanumeric transformer circuit identi-
fier; the first character of CKT must not be an ampersand ( & ), refer to Multi-
Section Line Grouping Data and Section 6.15.2, Outage Statistics Data File
Contents. CKT = 1 by default.

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CW The winding data I/O code defines the units in which the turns ratios WINDV1,
WINDV2 and WINDV3 are specified (the units of RMAn and RMIn are also
governed by CW when |CODn| is 1 or 2):
1 for off-nominal turns ratio in pu of winding bus base voltage
2 for winding voltage in kV
3 for off-nominal turns ratio in pu of nominal winding voltage, 
NOMV1, NOMV2 and NOMV3.
CW = 1 by default.
CZ The impedance data I/O code defines the units in which the winding impedances
R1-2, X1-2, R2-3, X2-3, R3-1 and X3-1 are specified:
1 for resistance and reactance in pu on system MVA base and 
winding voltage base
2 for resistance and reactance in pu on a specified MVA base and 
winding voltage base
3 for transformer load loss in watts and impedance magnitude in pu 
on a specified MVA base and winding voltage base.
In specifying transformer leakage impedances, the base voltage values are always
the nominal winding voltages that are specified on the third, fourth and fifth records
of the transformer data block (NOMV1, NOMV2 and NOMV3). If the default NOMVn
is not specified, it is assumed to be identical to the winding n bus base voltage.
CZ = 1 by default.
CM The magnetizing admittance I/O code defines the units in which MAG1 and MAG2
are specified:
1 for complex admittance in pu on system MVA base and Winding 1 
bus voltage base
2 for no load loss in watts and exciting current in pu on Winding 1 to 
two MVA base (SBASE1-2) and nominal Winding 1 voltage, NOMV1.
CM = 1 by default.
MAG1, The transformer magnetizing admittance connected to ground at bus I.
MAG2 When CM is 1, MAG1 and MAG2 are the magnetizing conductance and suscep-
tance, respectively, in pu on system MVA base and Winding 1 bus voltage base.
When a non-zero MAG2 is specified, it should be entered as a negative quantity.
When CM is 2, MAG1 is the no load loss in watts and MAG2 is the exciting current
in pu on Winding 1 to two MVA base (SBASE1-2) and nominal Winding 1 voltage
(NOMV1). For three-phase transformers or three-phase banks of single phase
transformers, MAG1 should specify the three-phase no-load loss. When a non-zero
MAG2 is specified, it should be entered as a positive quantity.
MAG1 = 0.0 and MAG2 = 0.0 by default.
NMETR The nonmetered end code of either 1 (for the Winding 1 bus) or 2 (for the Winding 2
bus). In addition, for a three-winding transformer, 3 (for the Winding 3 bus) is a valid
specification of NMETR. NMETR = 2 by default.

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NAME Alphanumeric identifier assigned to the transformer. NAME may be up to forty char-
acters and may contain any combination of blanks, uppercase letters, numbers and
special characters. NAME must be enclosed in single or double quotes if it contains
any blanks or special characters. NAME is blank by default.
STAT Transformer status of one for in-service and zero for out-of-service.
In addition, for a three-winding transformer, the following values of STAT provide for
one winding out-of-service with the remaining windings in-service:
2 for only Winding 2 out-of-service
3 for only Winding 3 out-of-service
4 for only Winding 1 out-of-service
STAT = 1 by default.
Oi An owner number (1 through 9999). Each transformer may have up to four owners.
By default, O1 is the owner to which bus I is assigned and O2, O3, and O4 are zero.
Fi The fraction of total ownership assigned to owner Oi; each Fi must be positive. The
Fi values are normalized such that they sum to 1.0 before they are placed in the
working case. By default, each Fi is 1.0.
VECGRP Alphanumeric identifier specifying vector group based on transformer winding
connections and phase angles. VECGRP value is used for information purpose
only. VECGRP is 12 blanks by default.
ZCOD Method to be used in deriving actual transformer impedances in applying trans-
former impedance adjustment tables:
0 apply impedance adjustment factors to winding impedances
1 apply impedance adjustment factors to bus-to-bus impedances
ZCOD = 0 by default.
ZCOD value is used only for three winding transformers. It is not used for two
winding transformers.
For three winding transformers, winding impedances are the equivalent T-model
impedances Z1, Z2 and Z3; and the bus-to-bus impedances are impedances Z12,
Z23 and Z31.
For three winding transformers and bus-to-bus impedance correction factors, only
one of the three windings must be adjustable (only one of COD1, COD2 and COD3
can be non-zero).

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The first three data items on the second record are read for both two- and three-winding trans-
formers; the remaining data items are used only for three-winding transformers:

R1-2, X1-2 The measured impedance of the transformer between the buses to which its first
and second windings are connected.
When CZ is 1, they are the resistance and reactance, respectively, in pu on system
MVA base and winding voltage base.
When CZ is 2, they are the resistance and reactance, respectively, in pu on Winding
1 to 2 MVA base (SBASE1-2) and winding voltage base.
When CZ is 3, R1-2 is the load loss in watts, and X1-2 is the impedance magnitude
in pu on Winding 1 to 2 MVA base (SBASE1-2) and winding voltage base. For
three-phase transformers or three-phase banks of single phase transformers, R1-2
should specify the three-phase load loss.
R1-2 = 0.0 by default, but no default is allowed for X1-2.
SBASE1-2 The Winding 1 to 2 three-phase base MVA of the transformer. SBASE1-2 = SBASE
(the system base MVA) by default.
R2-3, X2-3 The measured impedance of a three-winding transformer between the buses to
which its second and third windings are connected; ignored for a two-winding
transformer.
When CZ is 1, they are the resistance and reactance, respectively, in pu on system
MVA base and winding voltage base.
When CZ is 2, they are the resistance and reactance, respectively, in pu on Winding
2 to 3 MVA base (SBASE2-3) and winding voltage base.
When CZ is 3, R2-3 is the load loss in watts, and X2-3 is the impedance magnitude
in pu on Winding 2 to 3 MVA base (SBASE2-3) and winding voltage base. For
three-phase transformers or three-phase banks of single phase transformers, R2-3
should specify the three-phase load loss.
R2-3 = 0.0 by default, but no default is allowed for X2-3.
SBASE2-3 The Winding 2 to 3 three-phase base MVA of a three-winding transformer; ignored
for a two-winding transformer. SBASE2-3 = SBASE (the system base MVA) by
default.
R3-1, X3-1 The measured impedance of a three-winding transformer between the buses to
which its third and first windings are connected; ignored for a two-winding
transformer.
When CZ is 1, they are the resistance and reactance, respectively, in pu on system
MVA base and winding voltage base.
When CZ is 2, they are the resistance and reactance, respectively, in pu on Winding
3 to 1 MVA base (SBASE3-1) and winding voltage base.
When CZ is 3, R3-1 is the load loss in watts, and X3-1 is the impedance magnitude
in pu on Winding 3 to 1 MVA base (SBASE3-1) and winding voltage base. For
three-phase transformers or three-phase banks of single phase transformers, R3-1
should specify the three-phase load loss.
R3-1 = 0.0 by default, but no default is allowed for X3-1.
SBASE3-1 The Winding 3 to 1 three-phase base MVA of a three-winding transformer; ignored
for a two-winding transformer. SBASE3-1 = SBASE (the system base MVA) by
default.

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VMSTAR The voltage magnitude at the hidden star point bus; entered in pu. VMSTAR = 1.0
by default.
ANSTAR The bus voltage phase angle at the hidden star point bus; entered in degrees.
ANSTAR = 0.0 by default.

All data items on the third record are read for both two- and three-winding transformers:

WINDV1 When CW is 1, WINDV1 is the Winding 1 off-nominal turns ratio in pu of Winding 1

bus base voltage; WINDV1 = 1.0 by default.
When CW is 2, WINDV1 is the actual Winding 1 voltage in kV; WINDV1 is equal to
the base voltage of bus I by default.
When CW is 3, WINDV1 is the Winding 1 off-nominal turns ratio in pu of nominal
Winding 1 voltage, NOMV1; WINDV1 = 1.0 by default.
NOMV1 The nominal (rated) Winding 1 voltage base in kV, or zero to indicate that nominal
Winding 1 voltage is assumed to be identical to the base voltage of bus I. NOMV1 is
used in converting magnetizing data between physical units and per unit admittance
values when CM is 2. NOMV1 is used in converting tap ratio data between values in
per unit of nominal Winding 1 voltage and values in per unit of Winding 1 bus base
voltage when CW is 3. NOMV1 = 0.0 by default.
ANG1 The winding one phase shift angle in degrees. For a two-winding transformer,
ANG1 is positive when the winding one bus voltage leads the winding two bus
voltage; for a three-winding transformer, ANG1 is positive when the winding one
bus voltage leads the T (or star) point bus voltage. ANG1 must be greater than -
180.0º and less than or equal to +180.0º. ANG1 = 0.0 by default.
RATEn1 Winding 1’s twelve three-phase ratings, entered in either MVA or current expressed
as MVA, according to the value specified for XFRRAT specified on the first data
record (refer to Case Identification Data). Each RATEn1 = 0.0 (bypass loading limit
check for this transformer winding) by default.
COD1 The transformer control mode for automatic adjustments of the Winding 1 tap or
phase shift angle during power flow solutions:
0 for fixed tap and fixed phase shift
±1 for voltage control
±2 for reactive power flow control
±3 for active power flow control
±4 for control of a dc line quantity (valid only for two-winding 
transformers)
±5 for asymmetric active power flow control.
If the control mode is entered as a positive number, automatic adjustment of this
transformer winding is enabled when the corresponding adjustment is activated
during power flow solutions; a negative control mode suppresses the automatic
adjustment of this transformer winding. COD1 = 0 by default.

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CONT1 The bus number, or extended bus name enclosed in single quotes (refer to
Extended Bus Names), of the bus for which voltage is to be controlled by the trans-
former turns ratio adjustment option of the power flow solution activities when
COD1 is 1. CONT1 should be non-zero only for voltage controlling transformer
windings.
CONT1 may specify a bus other than I, J, or K; in this case, the sign of CONT1
defines the location of the controlled bus relative to the transformer winding. If
CONT1 is entered as a positive number, or a quoted extended bus name, the ratio
is adjusted as if bus CONT1 is on the Winding 2 or Winding 3 side of the trans-
former; if CONT1 is entered as a negative number, or a quoted extended bus name
with a minus sign preceding the first character, the ratio is adjusted as if bus
|CONT1| is on the Winding 1 side of the transformer. CONT1 = 0 by default.
RMA1, When |COD1| is 1, 2, 3, or 5, the upper and lower limits, respectively, of one of the
RMI1 following:
• Off-nominal turns ratio in pu of Winding 1 bus base voltage when |COD1| is
1 or 2 and CW is 1; RMA1 = 1.1 and RMI1 = 0.9 by default.
• Actual Winding 1 voltage in kV when |COD1| is 1 or 2 and CW is 2. No
default is allowed.
• Off-nominal turns ratio in pu of nominal Winding 1 voltage (NOMV1) when
|COD1| is 1 or 2 and CW is 3; RMA1 = 1.1 and RMI1 = 0.9 by default.
• Phase shift angle in degrees when |COD1| is 3 or 5. No default is allowed.
Not used when |COD1| is 0 or 4; RMA1 = 1.1 and RMI1 = 0.9 by default.
VMA1, When |COD1| is 1, 2, 3, or 5, the upper and lower limits, respectively, of one of the
VMI1 following:
• Voltage at the controlled bus (bus |CONT1|) in pu when |COD1| is 1. 
VMA1 = 1.1 and VMI1 = 0.9 by default.
• Reactive power flow into the transformer at the Winding 1 bus end in Mvar
when |COD1| is 2. No default is allowed.
• Active power flow into the transformer at the Winding 1 bus end in MW when
|COD1| is 3 or 5. No default is allowed.
Not used when |COD1| is 0 or 4; VMA1 = 1.1 and VMI1 = 0.9 by default.
NTP1 The number of tap positions available; used when COD1 is 1 or 2. NTP1 must be
between 2 and 9999. NTP1 = 33 by default.
TAB1 The number of a transformer impedance correction table if this transformer
winding’s impedance is to be a function of either off-nominal turns ratio or phase
shift angle (refer to Transformer Impedance Correction Tables), or 0 if no trans-
former impedance correction is to be applied to this transformer winding. TAB1 = 0
by default.
For three winding transformers, these impedance correction factors are applied to
the equivalent T-model impedance Z1 when ZCOD=0 and to the bus-to-bus imped-
ance Z12 when ZCOD=1.
CR1, CX1 The load drop compensation impedance for voltage controlling transformers
entered in pu on system base quantities; used when COD1 is 1. CR1 + j CX1 = 0.0
by default.

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CNXA1 Winding connection angle in degrees; used when COD1 is 5. There are no restric-
tions on the value specified for CNXA1; if it is outside of the range from -90.0 to
+90.0, CNXA1 is normalized to within this range. CNXA1 = 0.0 by default.

The first two data items on the fourth record are read for both two- and three-winding transformers;
the remaining data items are used only for three-winding transformers:

WINDV2 When CW is 1, WINDV2 is the Winding 2 off-nominal turns ratio in pu of Winding 2

bus base voltage; WINDV2 = 1.0 by default.
When CW is 2, WINDV2 is the actual Winding 2 voltage in kV; WINDV2 is equal to
the base voltage of bus J by default.
When CW is 3, WINDV2 is the Winding 2 off-nominal turns ratio in pu of nominal
Winding 2 voltage, NOMV2; WINDV2 = 1.0 by default.
NOMV2 The nominal (rated) Winding 2 voltage base in kV, or zero to indicate that nominal
Winding 2 voltage is assumed to be identical to the base voltage of bus J. NOMV2
is used in converting tap ratio data between values in per unit of nominal Winding 2
voltage and values in per unit of Winding 2 bus base voltage when CW is 3.
NOMV2 = 0.0 by default.
ANG2 The winding two phase shift angle in degrees. ANG2 is ignored for a two-winding
transformer. For a three-winding transformer, ANG2 is positive when the winding
two bus voltage leads the T (or star) point bus voltage. ANG2 must be greater than
-180.0º and less than or equal to +180.0º. ANG2 = 0.0 by default.
RATEn2 Winding 2’s twelve three-phase ratings, entered in either MVA or current expressed
as MVA, according to the value specified for XFRRAT specified on the first data
record (refer to Case Identification Data). Each RATEn2 = 0.0 (bypass loading limit
check for this transformer winding) by default.
COD2 The transformer control mode for automatic adjustments of the Winding 2 tap or
phase shift angle during power flow solutions:
0 for fixed tap and fixed phase shift
±1 for voltage control
±2 for reactive power flow control
±3 for active power flow control
±5 for asymmetric active power flow control.
If the control mode is entered as a positive number, automatic adjustment of this
transformer winding is enabled when the corresponding adjustment is activated
during power flow solutions; a negative control mode suppresses the automatic
adjustment of this transformer winding. COD2 = 0 by default.

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CONT2 The bus number, or extended bus name enclosed in single quotes (refer to
Extended Bus Names), of the bus for which voltage is to be controlled by the trans-
former turns ratio adjustment option of the power flow solution activities when
COD2 is 1. CONT2 should be non-zero only for voltage controlling transformer
windings.
CONT2 may specify a bus other than I, J, or K; in this case, the sign of CONT2
defines the location of the controlled bus relative to the transformer winding. If
CONT2 is entered as a positive number, or a quoted extended bus name, the ratio
is adjusted as if bus CONT2 is on the Winding 1 or Winding 3 side of the trans-
former; if CONT2 is entered as a negative number, or a quoted extended bus name
with a minus sign preceding the first character, the ratio is adjusted as if bus
|CONT2| is on the Winding 2 side of the transformer. CONT2 = 0 by default.
RMA2, When |COD2| is 1, 2, 3, or 5, the upper and lower limits, respectively, of one of the
RMI2 following:
• Off-nominal turns ratio in pu of Winding 2 bus base voltage when |COD2| is
1 or 2 and CW is 1; RMA2 = 1.1 and RMI2 = 0.9 by default.
• Actual Winding 2 voltage in kV when |COD2| is 1 or 2 and CW is 2. No default
is allowed.
• Off-nominal turns ratio in pu of nominal Winding 2 voltage (NOMV2) when
|COD2| is 1 or 2 and CW is 3; RMA2 = 1.1 and RMI2 = 0.9 by default.
• Phase shift angle in degrees when |COD2| is 3 or 5. No default is allowed.
Not used when |COD2| is 0; RMA2 = 1.1 and RMI2 = 0.9 by default.
VMA2, When |COD2| is 1, 2, 3, or 5, the upper and lower limits, respectively, of one of the
VMI2 following:
• Voltage at the controlled bus (bus |CONT2|) in pu when |COD2| is 1.
VMA2 = 1.1 and VMI2 = 0.9 by default.
• Reactive power flow into the transformer at the Winding 2 bus end in Mvar
when |COD2| is 2. No default is allowed.
• Active power flow into the transformer at the Winding 2 bus end in MW when
|COD2| is 3 or 5. No default is allowed.
Not used when |COD2| is 0; VMA2 = 1.1 and VMI2 = 0.9 by default.
NTP2 The number of tap positions available; used when COD2 is 1 or 2. NTP2 must be
between 2 and 9999. NTP2 = 33 by default.
TAB2 The number of a transformer impedance correction table if this transformer
winding’s impedance is to be a function of either off-nominal turns ratio or phase
shift angle (refer to Transformer Impedance Correction Tables), or 0 if no trans-
former impedance correction is to be applied to this transformer winding. TAB2 = 0
by default.
For three winding transformers, these impedance correction factors are applied to
the equivalent T-model impedance Z2 when ZCOD=0 and to the bus-to-bus imped-
ance Z23 when ZCOD=1.
CR2, CX2 The load drop compensation impedance for voltage controlling transformers
entered in pu on system base quantities; used when COD2 is 1. CR2 + j CX2 = 0.0
by default.

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CNXA2 Winding connection angle in degrees; used when COD2 is 5. There are no restric-
tions on the value specified for CNXA2; if it is outside of the range from -90.0 to
+90.0, CNXA2 is normalized to within this range. CNXA2 = 0.0 by default.

The fifth data record is specified only for three-winding transformers:

WINDV3 When CW is 1, WINDV3 is the Winding 3 off-nominal turns ratio in pu of Winding 3

bus base voltage; WINDV3 = 1.0 by default.
When CW is 2, WINDV3 is the actual Winding 3 voltage in kV; WINDV3 is equal to
the base voltage of bus K by default.
When CW is 3, WINDV3 is the Winding 3 off-nominal turns ratio in pu of nominal
Winding 3 voltage, NOMV3; WINDV3 = 1.0 by default.
NOMV3 The nominal (rated) Winding 3 voltage base in kV, or zero to indicate that nominal
Winding 3 voltage is assumed to be identical to the base voltage of bus K. NOMV3
is used in converting tap ratio data between values in per unit of nominal Winding 3
voltage and values in per unit of Winding 3 bus base voltage when CW is 3. NOMV3
= 0.0 by default.
ANG3 The winding three phase shift angle in degrees. ANG3 is positive when the winding
three bus voltage leads the T (or star) point bus voltage. ANG3 must be greater
than -180.0º and less than or equal to +180.0º. ANG3 = 0.0 by default.
RATEn3 Winding 3’s twelve three-phase ratings, entered in either MVA or current expressed
as MVA, according to the value specified for XFRRAT specified on the first data
record (refer to Case Identification Data). Each RATEn3 = 0.0 (bypass loading limit
check for this transformer winding) by default.
COD3 The transformer control mode for automatic adjustments of the Winding 3 tap or
phase shift angle during power flow solutions:
0 for fixed tap and fixed phase shift
±1 for voltage control
±2 for reactive power flow control
±3 for active power flow control
±5 for asymmetric active power flow control.
If the control mode is entered as a positive number, automatic adjustment of this
transformer winding is enabled when the corresponding adjustment is activated
during power flow solutions; a negative control mode suppresses the automatic
adjustment of this transformer winding. COD3 = 0 by default.
CONT3 The bus number, or extended bus name enclosed in single quotes (refer to
Extended Bus Names), of the bus for which voltage is to be controlled by the trans-
former turns ratio adjustment option of the power flow solution activities when
COD3 is 1. CONT3 should be non-zero only for voltage controlling transformer
windings.
CONT3 may specify a bus other than I, J, or K; in this case, the sign of CONT3
defines the location of the controlled bus relative to the transformer winding. If
CONT3 is entered as a positive number, or a quoted extended bus name, the ratio
is adjusted as if bus CONT3 is on the Winding 1 or Winding 2 side of the trans-
former; if CONT3 is entered as a negative number, or a quoted extended bus name
with a minus sign preceding the first character, the ratio is adjusted as if bus
|CONT3| is on the Winding 3 side of the transformer. CONT3 = 0 by default.

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RMA3, When |COD3| is 1, 2, 3, or 5, the upper and lower limits, respectively, of one of the
RMI3 following:
• Off-nominal turns ratio in pu of Winding 3 bus base voltage when |COD3| is
1 or 2 and CW is 1; RMA3 = 1.1 and RMI3 = 0.9 by default.
• Actual Winding 3 voltage in kV when |COD3| is 1 or 2 and CW is 2. No default
is allowed.
• Off-nominal turns ratio in pu of nominal Winding 3 voltage (NOMV3) when
|COD3| is 1 or 2 and CW is 3; RMA3 = 1.1 and RMI3 = 0.9 by default.
• Phase shift angle in degrees when |COD3| is 3 or 5. No default is allowed.
Not used when |COD3| is 0; RMA3 = 1.1 and RMI3 = 0.9 by default.
VMA3, When |COD3| is 1, 2, 3, or 5, the upper and lower limits, respectively, of one of the
VMI3 following:
• Voltage at the controlled bus (bus |CONT3|) in pu when |COD3| is 1.
VMA3 = 1.1 and VMI3 = 0.9 by default.
• Reactive power flow into the transformer at the Winding 3 bus end in Mvar
when |COD3| is 2. No default is allowed.
• Active power flow into the transformer at the Winding 3 bus end in MW when
|COD3| is 3 or 5. No default is allowed.
Not used when |COD3| is 0; VMA3 = 1.1 and VMI3 = 0.9 by default.
NTP3 The number of tap positions available; used when COD3 is 1 or 2. NTP3 must be
between 2 and 9999. NTP3 = 33 by default.
TAB3 The number of a transformer impedance correction table if this transformer
winding’s impedance is to be a function of either off-nominal turns ratio or phase
shift angle (refer to Transformer Impedance Correction Tables), or 0 if no trans-
former impedance correction is to be applied to this transformer winding. TAB3 = 0
by default.
For three winding transformers, these impedance correction factors are applied to
the equivalent T-model impedance Z3 when ZCOD=0 and to the bus-to-bus imped-
ance Z31 when ZCOD=1.
CR3, CX3 The load drop compensation impedance for voltage controlling transformers
entered in pu on system base quantities; used when COD3 is 1. CR3 + j CX3 = 0.0
by default.
CNXA3 Winding connection angle in degrees; used when COD3 is 5. There are no restric-
tions on the value specified for CNXA3; if it is outside of the range from -90.0 to
+90.0, CNXA3 is normalized to within this range. CNXA3 = 0.0 by default.

Transformer data input is terminated with a record specifying a Winding 1 bus number of zero.

Three-Winding Transformer Notes

The transformer data record blocks described in Transformer Data provide for the specification of
both two-winding transformers and three-winding transformers. A three-winding transformer is
modeled in PSS®E as a grouping of three two-winding transformers, where each of these two-
winding transformers models one of the windings. While most of the three-winding transformer data
is stored in the two-winding transformer data arrays, it is accessible for reporting and modification
only as three-winding transformer data.

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Program Operation Manual Transformer Data

In deriving winding impedances from the measured impedance data input values, one winding with
a small impedance, in many cases negative, often results. In the extreme case, it is possible to
specify a set of measured impedances that themselves do not individually appear to challenge the
precision limits of typical power system calculations, but which result in one winding impedance of
nearly (or identically) 0.0. Such data could result in precision difficulties, and hence inaccurate
results, when processing the system matrices in power flow and short circuit calculations.

Whenever a set of measured impedance results in a winding reactance that is identically 0.0, a
warning message is printed by the three-winding transformer data input or data changing function,
and the winding’s reactance is set to the zero impedance line threshold tolerance (or to 0.0001 if
the zero impedance line threshold tolerance itself is 0.0). Whenever a set of measured impedances
results in a winding impedance for which magnitude is less than 0.00001, a warning message is
printed. As with all warning and error messages produced during data input and data modification
phases of PSS®E, the user should resolve the cause of the message (e.g., was correct input data
specified?) and use engineering judgement to resolve modeling issues (e.g., is this the best way to
model this transformer or would some other modeling be more appropriate?).

Activity BRCH may be used to detect the presence of branch reactance magnitudes less than a
user-specified threshold tolerance; its use is always recommended whenever the user begins
power system analysis work using a new or modified system model.

Example Two-Winding Transformer Data Records

Figure 1-10 shows the data records for a 50 MVA, 138/34.5 kV two-winding transformer connected
to system buses with nominal voltages of 134 kV and 34.5 kV, and sample data on 100 MVA system
base and winding voltage bases of 134 kV and 34.5 kV.

Example of 2-Winding Transformer:

Data Formats

I, J, K, CKT, CW, CZ, CM, MAG1, MAG2, NMETR, ’NAME’, STAT, 01, F1, ..., 04, F4, VECGRP,ZCOD

R1-2, X1-2, SBASE1-2

WINDV1, NOMV1, ANG1, RATE11... RATE121, COD1, CONT1, RMA1, RMI1, VMA1, VMI1, NTP1, TAB1,
CR1, CX1, CNXA1

WINDV2, NOMV2

Data

6150, 6151, 0, ’1’, 1, 1, 1, 0.0, 0.0, 2, ’TWO-WINDINGS’, 1, 5, 1.0

0.0, 0.30, 100.0

1.01, 0.0, 0.0, 50.0, 60.0, 75.0, 0, 0, 0, 0, 0, 0, 0, 0, 0, 1, 6151, 1.1, 0.9, 1.025, 1.0, 33, 0, 0.0, 0.0

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1.0, 0.0

Figure 1-10. Sample Data for Two-Winding Transformer

Example Three-Winding Transformer Data Records

Figure 1-11 shows the data records for a 300 MVA, 345/138/13.8 kV three-winding transformer con-
nected to system buses with nominal voltages of 345 kV, 138 kV and 13.8 kV, respectively, and
sample data on 100 MVA system base and winding base voltages of 345 kV, 138 kV and 13.8 kV.

Example of 3-Winding Transformer:

Data Formats

I, J, K, CKT, CW, CZ, CM, MAG1, MAG2, NMETR, ’NAME’, STAT, 01, F1, ..., 04, F4, VECGRP,ZCOD

R1-2, X1-2, SBASE1-2, R2-3, X2-3, SBASE2-3, R3-1, X3-1, SBASE3-1, VMSTAR, ANSTAR

WINDV1, NOMV1, ANG1, RATE11... RATE121, COD1, CONT1, RMA1, RMI1, VMA1, VMI1, NTP1, TAB1,
CR1, CX1, CNXA1

WINDV2, NOMV2, ANG2, RATE12... RATE122, COD2, CONT2, RMA2, RMI2, VMA2, VMI2, NTP2, TAB2,
CR2, CX2, CNXA2

WINDV3, NOMV3, ANG3, RATE13... RATE123, COD3, CONT3, RMA3, RMI3, VMA3, VMI3, NTP3, TAB3,
CR3, CX3, CNXA3

Data

3001, 3002, 3000, ’1’, 1, 1, 1, 0.0, 0.0, 2, ’THREEWINDING’, 1, 5, 1.0

0.003, 0.03, 100.0, 0.001, 0.03, 100.0, 0.001, 0.035, 100.0, 1.025, 0.0

1.00, 0.0, 0.0, 300, 400, 600, 0, 0, 0, 0, 0, 0, 0, 0, 0, 0, 3001, 1.1, 0.9, 1.04, 1.0, 33, 0, 0.0, 0.0, 0.0

1.02, 0.0, 0.0, 300, 400, 600

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Program Operation Manual Transformer Data

1.00, 0.0, 0.0, 50, 60, 75

Figure 1-11. Sample Data for Three-Winding Transformer

Two Winding Transformer Vector Groups

Table 1-1, Examples of Two Winding Transformer Vector Groups shows examples of two winding
transformer vector groups, corresponding phase angles and connection codes. A different winding
clock position can be used by appropriately specifying the phase angle ANG1.

Table 1-1. Examples of Two Winding Transformer Vector Groups

PSSE
Phase Transformer Connection Transformer Connection
Vector
Angle Type Code (CC) Type Code (CC)
Group
(ANG1)

YNyn0 0 shell 11 core 20

YNyn6 180 shell 11 core 20
YNd1 30 shell 12
YNd11 -30 shell 12
YNd5 150 shell 12
YNd7 -150 shell 12
ZNd0 0 shell 12 core 17
ZNd1 30 shell 12 core 17
ZNd6 180 shell 12 core 17
ZNd7 -150 shell 12 core 17
ZNyn1 30 shell 12 core 17
ZNyn11 -30 shell 12 core 17
ZNyn5 150 shell 12 core 17
ZNyn7 -150 shell 12 core 17
ZNy1 30 shell 12 core 17
ZNy11 -30 shell 12 core 17

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Table 1-1. Examples of Two Winding Transformer Vector Groups

PSSE
Phase Transformer Connection Transformer Connection
Vector
Angle Type Code (CC) Type Code (CC)
Group
(ANG1)

ZNy5 150 shell 12 core 17

ZNy7 -150 shell 12 core 17
Dyn1 30 shell 13
Dyn11 -30 shell 13
Dyn5 150 shell 13
Dyn7 -150 shell 13
Dzn0 0 shell 13 core 16
Dzn1 30 shell 13 core 16
Dzn6 180 shell 13 core 16
Dzn7 -150 shell 13 core 16
YNzn1 30 shell 13 core 16
YNzn11 -30 shell 13 core 16
YNzn5 150 shell 13 core 16
YNzn7 -150 shell 13 core 16
Yzn1 30 shell 13 core 16
Yzn11 -30 shell 13 core 16
Yzn5 150 shell 13 core 16
Yzn7 -150 shell 13 core 16
Dd0 0 shell 14
Dd6 180 shell 14
Dy1 30 shell 14
Dy11 -30 shell 14
Dy5 150 shell 14
Dy7 -150 shell 14
Yd1 30 shell 14
Yd11 -30 shell 14
Yd5 150 shell 14
Yd7 -150 shell 14
YNy0 0 shell 14 core 12

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Program Operation Manual Transformer Data

Table 1-1. Examples of Two Winding Transformer Vector Groups

PSSE
Phase Transformer Connection Transformer Connection
Vector
Angle Type Code (CC) Type Code (CC)
Group
(ANG1)

YNy6 180 shell 14 core 12

Yyn0 0 shell 14 core 13
Yyn6 180 shell 14 core 13
Yy0 0 shell 14
Yy6 180 shell 14
YNa0 0 core 18 or 19 shell 21
Ya0 0 core 22 shell 14

Three Winding Transformer Vector Groups

Table 5-1, Branch Parameter Data Check Options shows examples of three winding transformer
vector groups, corresponding phase angles and connection codes. A different winding clock posi-
tion can be used by appropriately specifying the phase angles ANG1, ANG2 and ANG3.

Vector groups are specified forming combinations of allowed winding connections and clock posi-
tions for various transformer connection codes.

Table 1-2. Examples of Two Winding Transformer Vector Groups

Clock Positions and Phase Angles specified in Transformer Power Flow Data

Clock Position Phase Angles (ANG1/ANG2/ANG3)

0 0
6 180
1 -30
5 -150
7 150
11 30

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CC=11
Allowed Clock
Allowed Winding Configurations Positions
Winding 1 YN 0, 6
Winding 2 yn 0, 6
Winding 3 yn 0, 6
YN0yn6yn0, ANG1=0, ANG2=180, ANG3=0
Examples
YN0yn0yn0, ANG1=0, ANG2=0, ANG3=0

CC=12
Allowed Clock
Allowed Winding Configurations Positions
Winding 1 YN 0, 6
Winding 2 yn 0, 6
y 0, 6
Winding 3
d 1, 5, 7, 11
YN0yn6d5, ANG1=0, ANG2=180, ANG3=-150
Examples
YN6yn0y0 ANG1=180, ANG2=0, ANG3=0

CC=13
Allowed Clock
Allowed Winding Configurations Positions
Winding 1 D 1, 5, 7, 11
Winding 2 yn 0, 6
Winding 3 d 1, 5, 7, 11
D1YN0d1, ANG1=-30, ANG2=0, ANG3=0
Examples
D5YN0d5, ANG1=-150, ANG2=0, ANG3=-150

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Program Operation Manual Transformer Data

CC=14
Allowed Clock
Allowed Winding Configurations Positions
Y 0, 6
Winding 1
D 1, 5, 7, 11
y 0, 6
Winding 2
d 1, 5, 7, 11
y 0, 6
Winding 3
d 1, 5, 7, 11
Y6d11d7, ANG1=180, ANG2=30, ANG3=150
Examples
D1d1y6, ANG1=-30, ANG2=-30, ANG3=180

CC=15
Allowed Clock
Allowed Winding Configurations Positions
Winding 1* D 1, 5, 7, 11
Winding 2 yn 0, 6
Winding 3* d 1, 5, 7, 11
D1yn0d1, ANG1=-30, ANG2=0, ANG3=-30
Examples
D1yn6d11, ANG1= -30, ANG2=180, ANG3=30

* Note: Windings 1 and 3 form auto-transformer. So their clock positions are always identical.

CC=16
Allowed Clock
Allowed Winding Configurations Positions
Winding 1 YN 0, 6
Winding 2 yn 0, 6
Winding 3 yn 0, 6
YN0yn0yn0, ANG1=0, ANG2=0, ANG3=0
Examples
YN6yn0yn6, ANG1=180, ANG2=0, ANG3=180

CC=17
Allowed Clock
Allowed Winding Configurations Positions
Winding 1
YNa 0
Winding 2
Winding 3 d 1, 5, 7, 11
YNa0d1, ANG1=0, ANG2=0, ANG3=-30
Examples
YNa0d7, ANG1=0, ANG2=0, ANG3=150

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Areas, Zones and Owners Program Operation Manual

CC=18
Allowed Clock
Allowed Winding Configurations Positions
Winding 1
Ya 0
Winding 2
Winding 3 d 1, 5, 7, 11
Ya0d5, ANG1=0, ANG2=0, ANG3=-150
Examples
Ya0d11, ANG1=0, ANG2=0, ANG3=30

1.14 Areas, Zones and Owners

In the analysis of large scale power systems for both planning and operations purposes, it is often
convenient to be able to restrict the processing or reporting of PSS®E functions to one or more sub-
sets of the complete power system model. PSS®E provides three groupings of network elements
which may be used for these purposes: areas, zones, and owners.

Areas are commonly used to designate sections of the network that represent control areas
between which there are scheduled flows. PSS®E provides for the identification of areas and their
schedules. Alternatively, the network can be subdivided between utility companies or any other sub-
divisions useful for specific analyses. Each ac bus, load, and induction machine, as well as each dc
bus of each multi-terminal dc line, is assigned to an area.

Assigning buses to specific zones allows an additional subdivision of the network to facilitate anal-
yses and documentation. While PSS®E provides documentation of zone interchange, it provides
no analytical facility to schedule interchange between zones. Each ac bus, load, and induction
machine as well as each dc bus of each multi-terminal dc line, is assigned to a zone.

Although areas cannot overlap other areas and zones cannot overlap other zones, areas and zones
can overlap each other.

Figure 1-12 shows a system subdivided into three areas and three zones, each with a unique name.
Notice the following:

• An area does not have to be contiguous. Area #1 covers two separate parts of the
network.
• Zone #1 lies entirely in Area #1.
• Zone #2 lies partly in Area #1 and partly in Area #4.
• Zone #3 lies partly in Area 4 and Area 2.

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Figure 1-12. Overlapping Areas and Zones

Assigning ownership attributes to buses and other equipment allows an additional subdivision of
the network for analysis and documentation purposes. PSS®E provides neither analytical facility to
schedule interchange between owners, nor documentation of owner interchange. Each of the fol-
lowing power system elements is assigned to a single owner:

• ac bus
• load
• induction machine
• dc bus of a multi-terminal dc line
• FACTS device
• GNE device
Each of the following elements may have up to four owners:

• synchronous machine
• non-transformer branch
• two-winding and three-winding transformer
• VSC dc line
Area, zone and owner assignments are established at the time the network element is introduced
into the working case, either as specified by the user or to a documented default value. Assign-
ments may be modified either through the standard power flow data modification functions (refer to
Section 5.9, Changing Service Status and Power Flow Parametric Data) or via activities ARNM,
OWNM and ZONM.

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Additional Information
See also:
Section 4.8, Subsystem Selection
Section 4.9, Subsystem Reporting
Adjusting Net Interchange
Area Interchange Control
Area Interchange Data
Interarea Transfer Data
Owner Data
Zone Data
Bus Data
Load Data
Generator Data
Non-Transformer Branch Data
Transformer Data
Voltage Source Converter (VSC) DC Transmission Line Data
Multi-Terminal DC Transmission Line Data
Induction Machine Data
FACTS Device Data

1.15 Area Interchange Data

Area identifiers and interchange control parameters are specified in area interchange data records.
Data for each interchange area may be specified either at the time of raw data input or subsequently
via activity CHNG or the area [Spreadsheet]. Each area interchange data record has the following
format:

I, ISW, PDES, PTOL, 'ARNAME'

where:

I Area number (1 through 9999). No default allowed.

ISW Bus number, or extended bus name enclosed in single quotes (refer to Extended
Bus Names), of the area slack bus for area interchange control. The bus must be a
generator (Type 2) bus in the specified area. Any area containing a system swing
bus (Type 3) must have either that swing bus or a bus number of zero specified for
its area slack bus number. Any area with an area slack bus number of zero is
considered a floating area by the area interchange control option of the power flow
solution activities. ISW = 0 by default.
PDES Desired net interchange leaving the area (export); entered in MW. PDES must be
specified such that is consistent with the area interchange definition implied by the
area interchange control code (tie lines only, or tie lines and loads) to be specified
during power flow solutions (refer to Section 6.3.20, Automatic Adjustments and
Area Interchange Control). PDES = 0.0 by default.
PTOL Interchange tolerance bandwidth; entered in MW. PTOL = 10.0 by default.
ARNAME Alphanumeric identifier assigned to area I. ARNAME may be up to twelve charac-
ters and may contain any combination of blanks, uppercase letters, numbers and
special characters. ARNAME must be enclosed in single or double quotes if it
contains any blanks or special characters. ARNAME is twelve blanks by default.

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Program Operation Manual Two-Terminal DC Transmission Line Data

Area interchange data input is terminated with a record specifying an area number of zero.

Area Interchange Data Notes

All buses (ac and dc), loads and induction machines can be assigned to an area. The area number
is entered as part of the data records for the buses, loads, and induction machines (see Areas,
Zones and Owners, Bus Data, Load Data and Multi-Terminal DC Transmission Line Data).

Area interchange is a required net export of power from, or net import of power to, a specific area.
This does not imply that the power is destined to be transferred to or from any other specific area.
To specify transfers between specific pairs of areas, see Interarea Transfer Data.

Each bus in the PSS®E working case may be designated as residing in an interchange area, for
purposes of both interchange control and selective output and other processing. When the inter-
change control option is enabled during a power flow solution, each interchange area for which an
area slack bus is specified has the active power output of its area slack bus modified such that the
desired net interchange for the area falls within a desired band. Refer to Area Interchange Control
for further discussion on this option of the power flow solution activities.

1.16 Two-Terminal DC Transmission Line Data

The two-terminal dc transmission line model is used to simulate either a point-to-point system with
rectifier and inverter separated by a bipolar or mono-polar transmission system or a back-to-back
system where the rectifier and inverter are physically located at the same site and separated only
by a short bus-bar.


The data requirements fall into three groups:

• Control parameters and set-points

• Converter transformers
• The dc line characteristics
Each two-terminal dc transmission line to be represented in PSS®E is introduced by reading three
consecutive data records. Each set of dc line data records has the following format:

'NAME',MDC,RDC,SETVL,VSCHD,VCMOD,RCOMP,DELTI,METER,DCVMIN,CCCITMX,CCCACC
IPR,NBR,ANMXR,ANMNR,RCR,XCR,EBASR,TRR,TAPR,TMXR,TMNR,STPR,ICR,IFR,ITR,IDR,XCAPR
IPI,NBI,ANMXI,ANMNI,RCI,XCI,EBASI,TRI,TAPI,TMXI,TMNI,STPI,ICI,IFI,ITI,IDI,XCAPI

The first of the three dc line data records defines the following line quantities and control
parameters:

NAME The non-blank alphanumeric identifier assigned to this dc line. Each two-terminal dc
line must have a unique NAME. NAME may be up to twelve characters and may
contain any combination of blanks, uppercase letters, numbers and special charac-
ters. NAME must be enclosed in single or double quotes if it contains any blanks or
special characters. No default allowed.

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MDC Control mode: 0 for blocked, 1 for power, 2 for current. MDC = 0 by default.
RDC The dc line resistance; entered in ohms. No default allowed.
SETVL Current (amps) or power (MW) demand. When MDC is one, a positive value of
SETVL specifies desired power at the rectifier and a negative value specifies
desired inverter power. No default allowed.
VSCHD Scheduled compounded dc voltage; entered in kV. No default allowed.
VCMOD Mode switch dc voltage; entered in kV. When the inverter dc voltage falls below this
value and the line is in power control mode (i.e., MDC = 1), the line switches to
current control mode with a desired current corresponding to the desired power at
scheduled dc voltage. VCMOD = 0.0 by default.
RCOMP Compounding resistance; entered in ohms. Gamma and/or TAPI is used to attempt
to hold the compounded voltage (VDCI + DCCURRCOMP) at VSCHD. To control
the inverter end dc voltage VDCI, set RCOMP to zero; to control the rectifier end dc
voltage VDCR, set RCOMP to the dc line resistance, RDC; otherwise, set RCOMP
to the appropriate fraction of RDC. RCOMP = 0.0 by default.
DELTI Margin entered in per unit of desired dc power or current. This is the fraction by
which the order is reduced when ALPHA is at its minimum and the inverter is
controlling the line current. DELTI = 0.0 by default.
METER Metered end code of either R (for rectifier) or I (for inverter). METER = I by default.
DCVMIN Minimum compounded dc voltage; entered in kV. Only used in constant gamma
operation (i.e., when ANMXI = ANMNI) when TAPI is held constant and an ac trans-
former tap is adjusted to control dc voltage (i.e., when IFI, ITI, and IDI specify a two-
winding transformer). DCVMIN = 0.0 by default.
CCCITMX Iteration limit for capacitor commutated two-terminal dc line Newton solution proce-
dure. CCCITMX = 20 by default.
CCCACC Acceleration factor for capacitor commutated two-terminal dc line Newton solution
procedure. CCCACC = 1.0 by default.

The second of the three dc line data records defines rectifier end data quantities and control
parameters:

IPR Rectifier converter bus number, or extended bus name enclosed in single quotes
(refer to Extended Bus Names). No default allowed.
NBR Number of bridges in series (rectifier). No default allowed.
ANMXR Nominal maximum rectifier firing angle; entered in degrees. No default allowed.
ANMNR Minimum steady-state rectifier firing angle; entered in degrees. No default allowed.
RCR Rectifier commutating transformer resistance per bridge; entered in ohms. No
default allowed.
XCR Rectifier commutating transformer reactance per bridge; entered in ohms. No
default allowed.
EBASR Rectifier primary base ac voltage; entered in kV. No default allowed.
TRR Rectifier transformer ratio. TRR = 1.0 by default.

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TAPR Rectifier tap setting. TAPR = 1.0 by default.

If no two-winding transformer is specified by IFR, ITR, and IDR, TAPR is adjusted to
keep alpha within limits; otherwise, TAPR is held fixed and this transformer’s tap
ratio is adjusted. The adjustment logic assumes that the rectifier converter bus is on
the Winding 2 side of the transformer. The limits TMXR and TMNR specified here
are used; except for the transformer control mode flag (COD1 of Transformer Data),
the ac tap adjustment data is ignored.
TMXR Maximum rectifier tap setting. TMXR = 1.5 by default.
TMNR Minimum rectifier tap setting. TMNR = 0.51 by default.
STPR Rectifier tap step; must be positive. STPR = 0.00625 by default.
ICR Rectifier firing angle measuring bus number, or extended bus name enclosed in
single quotes (refer to Extended Bus Names). The firing angle and angle limits used
inside the dc model are adjusted by the difference between the phase angles at this
bus and the ac/dc interface (i.e., the converter bus, IPR). ICR = 0 by default.
IFR Winding 1 side from bus number, or extended bus name enclosed in single quotes,
of a two-winding transformer. IFR = 0 by default.
ITR Winding 2 side to bus number, or extended bus name enclosed in single quotes, of
a two-winding transformer. ITR = 0 by default.
IDR Circuit identifier; the branch described by IFR, ITR, and IDR must have been
entered as a two-winding transformer; an ac transformer may control at most only
one dc converter. IDR = '1' by default.
XCAPR Commutating capacitor reactance magnitude per bridge; entered in ohms.
XCAPR = 0.0 by default.

Data on the third of the three dc line data records contains the inverter quantities corresponding to
the rectifier quantities specified on the second record described above. The significant difference is
that the control angle ALFA for the rectifier is replaced by the control angle GAMMA for the inverter.

IPI,NBI,GAMMX,GAMMN,RCI,XCI,EBASI,TRI,TAPI,TMXI,TMNI,STPI,ICI,IFI,ITI,IDI,XCAPI

DC line data input is terminated with a record specifying a blank dc line name or a dc line name of
’0’.

Two-Terminal DC Line Data Notes

The steady-state two-terminal dc line model used in power flow analysis establishes the initial
steady state for dynamic analysis.

DC line converter buses, IPR and IPI, may be Type 1, 2, or 3 buses. Generators, loads, fixed and
switched shunt elements, induction machines other dc line converters, FACTS device sending
ends, and GNE devices are permitted at converter buses.

When either XCAPR > 0.0 or XCAPI > 0.0, the two-terminal dc line is treated as capacitor commu-
tated. Capacitor commutated two-terminal dc lines preclude the use of a remote ac transformer as
commutation transformer tap and remote commutation angle buses at either converter. Any data
provided in these fields are ignored for capacitor commutated two-terminal dc lines.

For additional information on dc line modeling in power flow solutions, refer to Section 6.3.17, DC
Lines.

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Voltage Source Converter (VSC) DC Transmission Line Data Program Operation Manual

1.17 Voltage Source Converter (VSC) DC Transmission Line Data

The voltage source converter (VSC) two-terminal dc transmission line model is used to simulate
either a point-to-point system or a back-to-back system using voltage source converters.


Each voltage source converter (VSC) dc line to be represented in PSS®E is introduced by reading
a set of three consecutive data records. Each set of VSC dc line data records has the following
format:

'NAME', MDC, RDC, O1, F1, ... O4, F4

IBUS,TYPE,MODE,DCSET,ACSET,ALOSS,BLOSS,MINLOSS,SMAX,IMAX,PWF,MAXQ,MINQ,REMOT,RMPCT
IBUS,TYPE,MODE,DCSET,ACSET,ALOSS,BLOSS,MINLOSS,SMAX,IMAX,PWF,MAXQ,MINQ,REMOT,RMPCT

The first of the three VSC dc line data records defines the following line quantities and control
parameters:

NAME The non-blank alphanumeric identifier assigned to this dc line. Each VSC dc line
must have a unique NAME. NAME may be up to twelve characters and may contain
any combination of blanks, uppercase letters, numbers and special characters.
NAME must be enclosed in single or double quotes if it contains any blanks or
special characters. No default allowed.
MDC Control mode: 0 for out-of-service, 1 for in-service. MDC = 1 by default.
RDC The dc line resistance; entered in ohms. RDC must be positive. No default allowed.
Oi An owner number (1 through 9999). Each VSC dc line may have up to four owners.
By default, O1 is 1, and O2, O3 and O4 are zero.
Fi The fraction of total ownership assigned to owner Oi; each Fi must be positive. The
Fi values are normalized such that they sum to 1.0 before they are placed in the
working case. By default, each Fi is 1.0.

The remaining two data records define the converter buses (converter 1 and converter 2), along
with their data quantities and control parameters:

IBUS Converter bus number, or extended bus name enclosed in single quotes (refer to
Extended Bus Names). No default allowed.
TYPE Code for the type of converter dc control:
0 for converter out-of-service
1 for dc voltage control
2 for MW control.
When both converters are in-service, exactly one converter of each VSC dc line
must be TYPE 1. No default allowed.

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Program Operation Manual Voltage Source Converter (VSC) DC Transmission Line Data

MODE Converter ac control mode:

1 for ac voltage control
2 for fixed ac power factor.
MODE = 1 by default.
DCSET Converter dc setpoint. For TYPE = 1, DCSET is the scheduled dc voltage on the dc
side of the converter bus; entered in kV. For TYPE = 2, DCSET is the power
demand, where a positive value specifies that the converter is feeding active power
into the ac network at bus IBUS, and a negative value specifies that the converter is
withdrawing active power from the ac network at bus IBUS; entered in MW. No
default allowed.
ACSET Converter ac setpoint. For MODE = 1, ACSET is the regulated ac voltage setpoint;
entered in pu. For MODE = 2, ACSET is the power factor setpoint. ACSET = 1.0 by
default.
Aloss, Coefficients of the linear equation used to calculate converter losses:
Bloss
KWconv loss = Aloss + (Idc * Bloss)
Aloss is entered in kW. Bloss is entered in kW/amp. Aloss = Bloss = 0.0 by default.
MINloss Minimum converter losses; entered in kW. MINloss = 0.0 by default.
SMAX Converter MVA rating; entered in MVA. SMAX = 0.0 to allow unlimited converter
MVA loading. SMAX = 0.0 by default.
IMAX Converter ac current rating; entered in amps. IMAX = 0.0 to allow unlimited
converter current loading. If a positive IMAX is specified, the base voltage assigned
to bus IBUS must be positive. IMAX = 0.0 by default.
PWF Power weighting factor fraction (0.0 < PWF < 1.0) used in reducing the active power
order and either the reactive power order (when MODE is 2) or the reactive power
limits (when MODE is 1) when the converter MVA or current rating is violated. When
PWF is 0.0, only the active power is reduced; when PWF is 1.0, only the reactive
power is reduced; otherwise, a weighted reduction of both active and reactive
power is applied. PWF = 1.0 by default.
MAXQ Reactive power upper limit; entered in Mvar. A positive value of reactive power indi-
cates reactive power flowing into the ac network from the converter; a negative
value of reactive power indicates reactive power withdrawn from the ac network.
Not used if MODE = 2. MAXQ = 9999.0 by default.
MINQ Reactive power lower limit; entered in Mvar. A positive value of reactive power indi-
cates reactive power flowing into the ac network from the converter; a negative
value of reactive power indicates reactive power withdrawn from the ac network.
Not used if MODE = 2. MINQ = -9999.0 by default.
REMOT Bus number, or extended bus name enclosed in single quotes (refer to Extended
Bus Names), of a remote Type 1 or 2 bus for which voltage is to be regulated by this
converter to the value specified by ACSET. If bus REMOT is other than a Type 1 or
2 bus, bus IBUS regulates its own voltage to the value specified by ACSET.
REMOT is entered as zero if the converter is to regulate its own voltage. Not used if
MODE = 2. REMOT = 0 by default.

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Transformer Impedance Correction Tables Program Operation Manual

RMPCT Percent of the total Mvar required to hold the voltage at the bus controlled by bus
IBUS that is to be contributed by this VSC; RMPCT must be positive. RMPCT is
needed only if REMOT specifies a valid remote bus and there is more than one
local or remote voltage controlling device (plant, switched shunt, FACTS device
shunt element, or VSC dc line converter) controlling the voltage at bus REMOT to a
setpoint, or REMOT is zero but bus IBUS is the controlled bus, local or remote, of
one or more other setpoint mode voltage controlling devices. Not used if MODE = 2.
RMPCT = 100.0 by default.

VSC dc line data input is terminated with a record specifying a blank dc line name or a dc line name
of ’0’.

VSC DC Line Data Notes

Each VSC dc line converter bus must have the following characteristics:

• It must be a Type 1 or 2 bus. Generators, loads, fixed and switched shunt elements,
induction machines, other dc line converters, FACTS device sending ends, and GNE
devices are permitted at converter buses.
• It must not have the terminal end of a FACTS device connected to the same bus.
• It must not be connected by a zero impedance line to another bus that violates any of
the above restrictions.
In specifying reactive power limits for converters that control ac voltage (i.e., those with unequal
reactive power limits where the MODE is 1), the use of very narrow var limit bands is discouraged.
The Newton-Raphson based power flow solutions require that the difference between the control-
ling equipment's high and low reactive power limits be greater than 0.002 pu for all setpoint mode
voltage controlling equipment (0.2 Mvar on a 100 MVA system base). It is recommended that
voltage controlling VSC converters have Mvar ranges substantially wider than this minimum per-
missible range.

For interchange and loss assignment purposes, the dc voltage controlling converter is assumed to
be the non-metered end of each VSC dc line. As with other network branches, losses are assigned
to the subsystem of the non-metered end, and flows at the metered ends are used in interchange
calculations.

For additional information on dc line modeling in power flow solutions, refer to Section 6.3.17 DC
Lines.

1.18 Transformer Impedance Correction Tables

Transformer impedance correction tables are used to model a change of transformer impedance as
off-nominal turns ratio or phase shift angle is adjusted. Data for each table may be specified either
at the time of raw data input, or subsequently via activity CHNG or the impedance table
[Spreadsheet].

Each impedance correction table may have up to 99 points. The scaling factors are complex num-
bers; the imaginary components of these factors may be specified as 0.0. Points are specified six
per line in the impedance correction table data block. As many records are needed (with six points
per record) are entered. End of data for a table is specified by specifying an additional point with the
three values defining the point all specified as 0.0.

Each transformer impedance correction table data block has the following format:

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Program Operation Manual Transformer Impedance Correction Tables

I, T1, Re(F1), Im(F1), T2, Re(F2), Im(F2), ... T6, Re(F6), Im(F6)
T7, Re(F7), Im(F7), T8, Re(F8), Im(F8), ... T12, Re(F12), Im(F12)
.
.
Tn, Re(Fn), Im(Fn), 0.0, 0.0, 0.0

where:

I Impedance correction table number (1 through the maximum number of impedance

correction tables at the current size level; refer to Table 3-1, Standard Maximum
PSS®E Program Capacities). No default allowed.
Ti Either off-nominal turns ratio in pu of the controlling windings bus voltage base or
phase shift angle in degrees. Ti = 0.0 by default.
Fi Complex scaling factor by which transformer nominal impedance is to be multiplied
to obtain the actual transformer impedance for the corresponding Ti. Fi = (0.0+j0.0)
by default. The impedances used in calculation of Fi should be expressed in percent
or pu on winding voltage base at specified tap position Ti and MVA base used in
power flow data. This is the same base as per CZ of power flow data but winding
voltage is at tap Ti.

Transformer impedance correction data input is terminated with a record specifying a table number
of zero.

Example:
Nominal Tap Position = 10, Winding Voltage = 132 kV, Impedance 123.118 ohms/phase, 
Off-Nominal Tap Position = 19, Winding Voltage = 151.8 kV

CZ = 2, Transformer MVA = 50
Tap Position Winding kV Z12 Data (ohms/phase) Base Z (ohms) PU
1 112.20 81.7016 251.7768 0.3245
10 132.0 123.1118 348.48 0.3532
19 151.8 178.8155 460.8648 0.3880

PSSE Impedance Correction Data

Ti Fi
0.85 0.9187
1.0 1.0
1.15 1.098277

Impedance Correction Table Notes

The Ti values on a transformer impedance correction table record block must all be either tap ratios
or phase shift angles. They must be entered in strictly ascending order; i.e., for each i, Ti+1>Ti. Each
Fi entered must be non-zero. For each table, at least 2 sets of values must be specified (plus the
additional end-of-table point of zeros), and up to 99 may be entered. For a graphical view of a cor-
rection table for which the imaginary component of each scaling factor is 0.0, see Figure 1-13.

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The Ti values for tables that are a function of tap ratio (rather than phase shift angle) in pu of the
controlling winding bus voltage base.

A transformer impedance is assigned to an impedance correction table either on the third, fourth or
fifth record of the transformer data record block of activities READ, TREA, RDCH (refer to Trans-
former Data), or via activity CHNG or the two-winding and three-winding transformer [Spreadsheets].
Each table may be shared among many transformer impedances. If the first T in a table is less than
0.5 or the last T entered is greater than 1.5, T is assumed to be the phase shift angle and each
transformer impedance dependent on the table is treated as a function of phase shift angle. Other-
wise, the transformer impedances dependent on the table are made sensitive to off-nominal turns
ratio.

For three-winding transformers, a data item associated with the transformer (ZCOD) indicates
whether impedance adjustment is to be applied to winding impedances or to the bus-to-bus imped-
ances. If applied to winding impedances, the input to the table look-up is the winding tap ratio or
phase shift angle, as appropriate, and the scaling factor is applied to the winding’s nominal
impedance.

When impedance adjustment is applied to the bus-to-bus impedances of a three-winding trans-

former, the following requirements must be met:

• exactly one winding of the transformer must be automatically adjustable.

• at least one winding must have an impedance correction table assigned to it.
• the impedance correction table(s) must be sensitive to the quantity that is automatically
adjustable (tap ratio or phase shift angle, as appropriate).
In this case, the input to each of the tables is the appropriate quantity (tap ratio or phase shift angle)
of the adjustable winding. If an impedance correction table is specified for winding 1, impedance
adjustment is applied to Z1-2; if an impedance correction table is specified for winding 2, impedance
adjustment is applied to Z2-3; and if an impedance correction table is specified for winding 3, imped-
ance adjustment is applied to Z3-1.

The power flow case stores both a nominal and actual impedance for each transformer winding
impedance. The value of transformer impedance entered in activities READ, TREA, RDCH, CHNG,
or the transformer [Spreadsheets] is taken as the nominal value of impedance. Each time the com-
plex tap setting of a transformer is changed, either automatically by the power flow solution activities
or manually by the user, and the modified quantity is an input to the table look-up function of any
impedance correction table associated with the transformer, actual transformer impedances are
redetermined if appropriate. First, the scaling factor is established from the appropriate table by
linear interpolation; then nominal impedance is multiplied by the scaling factor to determine actual
impedance. An appropriate message is printed any time the actual impedance is modified.

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Program Operation Manual Multi-Terminal DC Transmission Line Data

Figure 1-13. Typical Impedance Correction Factor Curve

1.19 Multi-Terminal DC Transmission Line Data

PSS®E allows the representation of up to 12 converter stations on one multi-terminal dc line. The
dc network of each multi-terminal dc line may consist of up to 20 dc network buses connected
together by up to 20 dc links.

Each multi-terminal dc transmission line to be represented in PSS®E is introduced by reading a

series of data records. Each set of multi-terminal dc line data records begins with a record that
defines the number of converters, number of dc buses and number of dc links as well as related
bus numbers and the control mode. Following this first record there are subsequent records for
each converter, each dc bus, and each dc link.

Each set of multi-terminal dc line data records begins with a record of system definition data in the
following format:

'NAME', NCONV, NDCBS, NDCLN, MDC, VCONV, VCMOD, VCONVN

where:

NAME The non-blank alphanumeric identifier assigned to this dc line. Each multi-terminal dc
line must have a unique NAME. NAME may be up to twelve characters and may
contain any combination of blanks, uppercase letters, numbers and special characters.
NAME must be enclosed in single or double quotes if it contains any blanks or special
characters. No default allowed.

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Multi-Terminal DC Transmission Line Data Program Operation Manual

NCONV Number of ac converter station buses in multi-terminal dc line I. No default allowed.

NDCBS Number of dc buses in multi-terminal dc line I (NCONV < NDCBS). No default allowed.
NDCLN Number of dc links in multi-terminal dc line I. No default allowed.
MDC Control mode:
0 for blocked
1 for power control
2 for current control
MDC = 0 by default.
VCONV Bus number, or extended bus name enclosed in single quotes (refer to Extended Bus
Names), of the ac converter station bus that controls dc voltage on the positive pole of
multi-terminal dc line I. Bus VCONV must be a positive pole inverter. No default
allowed.
VCMOD Mode switch dc voltage; entered in kV. When any inverter dc voltage magnitude falls
below this value and the line is in power control mode (i.e., MDC = 1), the line switches
to current control mode with converter current setpoints corresponding to their desired
powers at scheduled dc voltage. VCMOD = 0.0 by default.
VCONVN Bus number, or extended bus name enclosed in single quotes, of the ac converter
station bus that controls dc voltage on the negative pole of multi-terminal dc line I. If
any negative pole converters are specified (see below), bus VCONVN must be a
negative pole inverter. If the negative pole is not being modeled, VCONVN must be
specified as zero. VCONVN = 0 by default.

This data record is followed by NCONV converter records of the following format:

IB,N,ANGMX,ANGMN,RC,XC,EBAS,TR,TAP,TPMX,TPMN,TSTP,SETVL,DCPF,MARG,CNVCOD

where:

IB ac converter bus number, or extended bus name enclosed in single quotes (refer to
Extended Bus Names). No default allowed.
N Number of bridges in series. No default allowed.
ANGMX Nominal maximum ALPHA or GAMMA angle; entered in degrees. No default
allowed.
ANGMN Minimum steady-state ALPHA or GAMMA angle; entered in degrees. No default
allowed.
RC Commutating resistance per bridge; entered in ohms. No default allowed.
XC Commutating reactance per bridge; entered in ohms. No default allowed.
EBAS Primary base ac voltage; entered in kV. No default allowed.
TR Actual transformer ratio. TR = 1.0 by default.
TAP Tap setting. TAP = 1.0 by default.
TPMX Maximum tap setting. TPMX = 1.5 by default.
TPMN Minimum tap setting. TPMN = 0.51 by default.
TSTP Tap step; must be a positive number. TSTP = 0.00625 by default.

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Program Operation Manual Multi-Terminal DC Transmission Line Data

SETVL Converter setpoint. When IB is equal to VCONV or VCONVN, SETVL specifies the
scheduled dc voltage magnitude, entered in kV, across the converter. For other
converter buses, SETVL contains the converter current (amps) or power (MW)
demand; a positive value of SETVL indicates that bus IB is a rectifier, and a nega-
tive value indicates an inverter. No default allowed.
DCPF Converter participation factor. When the order at any rectifier in the multi-terminal
dc line is reduced, either to maximum current or margin, the orders at the remaining
converters on the same pole are modified according to their DCPFs to:
SETVL + (DCPF/SUM)R
where SUM is the sum of the DCPFs at the unconstrained converters on the same
pole as the constrained rectifier, and R is the order reduction at the constrained
rectifier. DCPF = 1. by default.
MARG Rectifier margin entered in per unit of desired dc power or current. The converter
order reduced by this fraction, (1.-MARG)SETVL, defines the minimum order for
this rectifier. MARG is used only at rectifiers. MARG = 0.0 by default.
CNVCOD Converter code. A positive value or zero must be entered if the converter is on the
positive pole of multi-terminal dc line I. A negative value must be entered for nega-
tive pole converters. CNVCOD = 1 by default.

These data records are followed by NDCBS dc bus records of the following format:

IDC, IB, AREA, ZONE, 'DCNAME', IDC2, RGRND, OWNER

where:

IDC dc bus number (1 to NDCBS). The dc buses are used internally within each multi-
terminal dc line and must be numbered 1 through NDCBS. No default allowed.
IB ac converter bus number, or extended bus name enclosed in single quotes (refer to
Extended Bus Names), or zero. Each converter station bus specified in a converter
record must be specified as IB in exactly one dc bus record. DC buses that are
connected only to other dc buses by dc links and not to any ac converter buses
must have a zero specified for IB. A dc bus specified as IDC2 on one or more other
dc bus records must have a zero specified for IB on its own dc bus record. IB = 0 by
default.
AREA Area number (1 through 9999). AREA = 1 by default.
ZONE Zone number (1 through 9999). ZONE = 1 by default.
DCNAME Alphanumeric identifier assigned to dc bus IDC. DCNAME may be up to twelve
characters and may contain any combination of blanks, uppercase letters, numbers
and special characters. DCNAME must be enclosed in single or double quotes if it
contains any blanks or special characters. DCNAME is twelve blanks by default.
IDC2 Second dc bus to which converter IB is connected, or zero if the converter is
connected directly to ground. For voltage controlling converters, this is the dc bus
with the lower dc voltage magnitude and SETVL specifies the voltage difference
between buses IDC and IDC2. For rectifiers, dc buses should be specified such that
power flows from bus IDC2 to bus IDC. For inverters, dc buses should be specified
such that power flows from bus IDC to bus IDC2. IDC2 is ignored on those dc bus
records that have IB specified as zero. IDC2 = 0 by default.

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RGRND Resistance to ground at dc bus IDC; entered in ohms. During solutions RGRND is
used only for those dc buses specified as IDC2 on other dc bus records.
RGRND = 0.0 by default.
OWNER Owner number (1 through 9999). OWNER = 1 by default.

These data records are followed by NDCLN dc link records of the following format:

IDC, JDC, DCCKT, MET, RDC, LDC

where:

IDC Branch from bus dc bus number. No default allowed.

JDC Branch to bus dc bus number. No default allowed.
DCCKT One-character uppercase alphanumeric branch circuit identifier. It is recommended
that single circuit branches be designated as having the circuit identifier 1. 
DCCKT = 1 by default.
MET Metered end flag:
<1 to designate bus IDC as the metered end
>2 to designate bus JDC as the metered end.
MET = 1 by default.
RDC dc link resistance, entered in ohms. No default allowed.
LDC dc link inductance, entered in mH. LDC is not used by the power flow solution activ-
ities but is available to multi-terminal dc line dynamics models. LDC = 0.0 by
default.

Multi-terminal dc line data input is terminated with a record specifying a dc line number of zero.

Multi-Terminal DC Line Notes

The following points should be noted in specifying multi-terminal dc line data:

• Conventional two-terminal (refer to Two-Terminal DC Transmission Line Data) and

multi-terminal dc lines are stored separately in PSS®E working memory. Therefore,
there may simultaneously exist, for example, a two-terminal dc line identified as dc line
ABC along with a multi-terminal line for which the name is ABC.
• Multi-terminal lines should have at least three converter terminals; conventional dc
lines consisting of two terminals should be modeled as two-terminal lines (refer to Two-
Terminal DC Transmission Line Data).
• AC converter buses may be Type 1, 2, or 3 buses. Generators, loads, fixed and
switched shunt elements, induction machines, other dc line converters, FACTS device
sending ends, and GNE devices are permitted at converter buses.
• Each multi-terminal dc line is treated as a subnetwork of dc buses and dc links con-
necting its ac converter buses. For each multi-terminal dc line, the dc buses must be
numbered 1 through NDCBS.
• Each ac converter bus must be specified as IB on exactly one dc bus record; there may
be dc buses connected only to other dc buses by dc links but not to any ac converter
bus.

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Program Operation Manual Multi-Section Line Grouping Data

• AC converter bus IB may be connected to a dc bus IDC, which is connected directly to

ground. IB is specified on the dc bus record for dc bus IDC; the IDC2 field is specified
as zero.
• Alternatively, ac converter bus IB may be connected to two dc buses IDC and IDC2,
the second of which is connected to ground through a specified resistance. IB and IDC2
are specified on the dc bus record for dc bus IDC; on the dc bus record for bus IDC2,
the ac converter bus and second dc bus fields (IB and IDC2, respectively) must be
specified as zero and the grounding resistance is specified as RGRND.
• The same dc bus may be specified as the second dc bus for more than one ac con-
verter bus.
• All dc buses within a multi-terminal dc line must be reachable from any other point
within the dc subnetwork.
• The area numbers assigned to dc buses and the metered end designations of dc links
are used in calculating area interchange and assigning losses in activities AREA, INTA,
TIES, and SUBS as well as in the interchange control option of the power flow solution
activities. Similarly, the zone assignments and metered end specifications are used in
activities ZONE, INTZ, TIEZ, and SUBS.
• Section 5.7.2 Reading RDCH Data Files Created by Previous Releases of PSS®E
describes the specification of NCONV, NDCBS and NDCLN when specifying changes
to an existing multi-terminal dc line in activity RDCH.
For additional information on dc line modeling in power flow solutions, refer to Section 6.3.17, DC
Lines.

A multi-terminal layout is shown in Figure 1-14. There are 4 convertors, 5 dc buses and 4 dc links.

Figure 1-14. Multi-Terminal DC Network

1.20 Multi-Section Line Grouping Data

Transmission lines commonly have a series of sections with varying physical structures. The sec-
tion might have different tower configurations, conductor types and bundles, or various

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combinations of these. The physical differences can result in the sections having different resis-
tance, reactance and charging.


A transmission line with several distinct sections can be represented as one multisection line group.

Each multi-section line grouping to be represented in PSS®E is introduced by reading a multi-sec-

tion line grouping data record. Each multi-section line grouping data record has the following format:

I, J, ID, MET, DUM1, DUM2, ... DUM9

where:

I From bus number, or extended bus name enclosed in single quotes (refer to
Extended Bus Names). No default allowed.
J To bus number, or extended bus name enclosed in single quotes. No default
allowed.
ID Two-character upper case alphanumeric multi-section line grouping identifier. The
first character must be an ampersand ( & ). ID = &1 by default.
MET Metered end flag:
<1 to designate bus I as the metered end
>2 to designate bus J as the metered end.
MET = 1 by default.
DUMi Bus numbers, or extended bus names enclosed in single quotes (refer to Extended
Bus Names), of the dummy buses connected by the branches that comprise this
multi-section line grouping. No defaults allowed.

Multi-section line grouping data input is terminated with a record specifying a from bus number of
zero.

Multi-Section Line Example

The DUMi values on each record define the branches connecting bus I to bus J, and are entered
so as to trace the path from bus I to bus J. Specifically, for a multi-section line grouping consisting
of three line sections (and hence two dummy buses):

I D1 D2 J
C1 C2 C3

The path from I to J is defined by the following branches:

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Program Operation Manual Zone Data

From To Circuit
I D1 C1
D1 D2 C2
D2 J C3

If this multi-section line grouping is to be assigned the line identifier &1, the corresponding multi-
section line grouping data record is given by:

I J &1 1 D1 D2

Multi-Section Line Notes

Up to 10 line sections (and hence 9 dummy buses) may be defined in each multi-section line
grouping. A branch may be a line section of at most one multi-section line grouping.

Each dummy bus must have exactly two branches connected to it, both of which must be members
of the same multi-section line grouping. A multi-section line dummy bus may not be a converter bus
of a dc transmission line. A FACTS control device may not be connected to a multi-section line
dummy bus.

The status of line sections and type codes of dummy buses are set such that the multi-section line
is treated as a single entity with regards to its service status.

When the multi-section line reporting option is enabled (refer to Section 3.3.3, Program Run-Time
Option Settings and activity OPTN), several power flow reporting activities such as POUT and
LOUT do not tabulate conditions at multi-section line dummy buses. Accordingly, care must be
taken in interpreting power flow output reports when dummy buses are other than passive nodes
(e.g., if load or generation is present at a dummy bus).

1.21 Zone Data

Zone identifiers are specified in zone data records. Zone names may be specified either at the time
of raw data input or subsequently via activity CHNG or the zone [Spreadsheet]. Each zone data
record has the following format:

I, 'ZONAME'

where:

I Zone number (1 through 9999). No default allowed.

ZONAME Alphanumeric identifier assigned to zone I. ZONAME may be up to twelve charac-
ters and may contain any combination of blanks, uppercase letters, numbers and
special characters. ZONAME must be enclosed in single or double quotes if it
contains any blanks or special characters. ZONAME is twelve blanks by default.

Zone data input is terminated with a record specifying a zone number of zero.

Zone Data Notes

All buses (ac and dc), loads, and induction machines can be assigned to a zone. The zone number
is entered as part of the data records for the buses, loads, and induction machines (see Areas,

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Zones and Owners, Bus Data, Load Data and Multi-Terminal DC Transmission Line Data).

The use of zones enables the user to develop reports and to check results on the basis of zones
and, consequently, be highly specific when reporting and interpreting analytical results.

1.22 Interarea Transfer Data

The PSS®E user has the ability to assign each bus, load, and induction machine to an area (see
Bus Data, Load Data, Multi-Terminal DC Transmission Line Data, Area Interchange Data and
Areas, Zones and Owners). Furthermore, the user can schedule active power transfers between
pairs of areas.


These active power transfers are specified in interarea transfer data records. Each interarea
transfer data record has the following format:

ARFROM, ARTO, TRID, PTRAN

where:

ARFROM From area number (1 through 9999). No default allowed.

ARTO To area number (1 through 9999). No default allowed.
TRID Single-character (0 through 9 or A through Z) upper case interarea transfer identifier
used to distinguish among multiple transfers between areas ARFROM and ARTO.
TRID = 1 by default.
PTRAN MW comprising this transfer. A positive PTRAN indicates that area ARFROM is
selling to area ARTO. PTRAN = 0.0 by default.

Interarea transfer data input is terminated with a record specifying a from area number of zero.

Interarea Transfer Data Notes

Following the completion of interarea transfer data input, activity READ generates an alarm for any
area for which at least one interarea transfer is present and where the sum of transfers differs from
its desired net interchange, PDES (refer to Area Interchange Data).

1.23 Owner Data

PSS®E allows the user to identify which organization or utility actually owns a facility, a piece of
equipment or a load. Buses (ac and dc), loads, induction machines, FACTS devices, and GNE
devices have provision for an owner, while machines, ac branches, and VSC dc lines can have up
to four different owners. Ownership is specified as part of the data records for these network ele-
ments (see Bus Data, Load Data, FACTS Device Data, Generator Data, Non-Transformer Branch
Data, Transformer Data, Voltage Source Converter (VSC) DC Transmission Line Data, Multi-Ter-
minal DC Transmission Line Data, and GNE Device Data).

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Program Operation Manual FACTS Device Data

The use of the ownership attribute enables the user to develop reports and to check results on the
basis of ownership and, consequently, be highly specific when reporting and interpreting analytical
results.


Owner identifiers are specified in owner data records. Owner names may be specified either at the
time of raw data input or subsequently via activity CHNG or the owner [Spreadsheet]. Each owner
data record has the following format:

I, 'OWNAME'

where:

I Owner number (1 through 9999). No default allowed.

OWNAME Alphanumeric identifier assigned to owner I. OWNAME may be up to twelve charac-
ters and may contain any combination of blanks, uppercase letters, numbers and
special characters. OWNAME must be enclosed in single or double quotes if it
contains any blanks or special characters. OWNAME is twelve blanks by default.

Owner data input is terminated with a record specifying an owner number of zero.

1.24 FACTS Device Data

There are a variety of Flexible AC Transmission System (FACTS) devices currently available.
These include shunt devices, such as the Static Compensator (STATCOM), series devices such as
the Static Synchronous Series Compensator (SSSC), combined devices such as the Unified Power
Flow Controller (UPFC), and parallel series devices such as the Interline Power Flow Controller
(IPFC).


PSS®E accepts data for all of these devices through one generic set of data records. Each FACTS
device to be represented in PSS®E is specified in FACTS device data records. Each FACTS device
data record has the following format:

’NAME’,I,J,MODE,PDES,QDES,VSET,SHMX,TRMX,VTMN,VTMX,VSMX,IMX,LINX,
RMPCT,OWNER,SET1,SET2,VSREF,REMOT,’MNAME’

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where:

NAME The non-blank alphanumeric identifier assigned to this FACTS device. Each FACTS
device must have a unique NAME. NAME may be up to twelve characters and may
contain any combination of blanks, uppercase letters, numbers and special charac-
ters. NAME must be enclosed in single or double quotes if it contains any blanks or
special characters. No default allowed.
I Sending end bus number, or extended bus name enclosed in single quotes (refer to
Extended Bus Names). No default allowed.
J Terminal end bus number, or extended bus name enclosed in single quotes; 0 for a
STATCON. J = 0 by default.
MODE Control mode:
For a STATCON (i.e., a FACTS devices with a shunt element but no series
element), J must be 0 and MODE must be either 0 or 1):
0 out-of-service (i.e., shunt link open)
1 shunt link operating.
For a FACTS device with a series element (i.e., J is not 0), MODE may be:
0 out-of-service (i.e., series and shunt links open)
1 series and shunt links operating.
2 series link bypassed (i.e., like a zero impedance line) and shunt link operating as a
STATCON.
3 series and shunt links operating with series link at constant series impedance.
4 series and shunt links operating with series link at constant series voltage.
5 master device of an IPFC with P and Q setpoints specified; another FACTS device
must be designated as the slave device (i.e., its MODE is 6 or 8) of this IPFC.
6 slave device of an IPFC with P and Q setpoints specified; the FACTS device specified
in MNAME must be the master device (i.e., its MODE is 5 or 7) of this IPFC. The Q
setpoint is ignored as the master device dictates the active power exchanged
between the two devices.
7 master device of an IPFC with constant series voltage setpoints specified; another
FACTS device must be designated as the slave device (i.e., its MODE is 6 or 8) of this
IPFC
8 slave device of an IPFC with constant series voltage setpoints specified; the FACTS
device specified in MNAME must be the master device (i.e., its MODE is 5 or 7) of this
IPFC. The complex Vd + jVq setpoint is modified during power flow solutions to reflect
the active power exchange determined by the master device
MODE = 1 by default.
PDES Desired active power flow arriving at the terminal end bus; entered in MW.
PDES = 0.0 by default.
QDES Desired reactive power flow arriving at the terminal end bus; entered in MVAR.
QDES = 0.0 by default.
VSET Voltage setpoint at the sending end bus; entered in pu. VSET = 1.0 by default.
SHMX Maximum shunt current at the sending end bus; entered in MVA at unity voltage.
SHMX = 9999.0 by default.
TRMX Maximum bridge active power transfer; entered in MW. TRMX = 9999.0 by default.
VTMN Minimum voltage at the terminal end bus; entered in pu. VTMN = 0.9 by default.
VTMX Maximum voltage at the terminal end bus; entered in pu. VTMX = 1.1 by default.

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VSMX Maximum series voltage; entered in pu. VSMX = 1.0 by default.

IMX Maximum series current, or zero for no series current limit; entered in MVA at unity
voltage. IMX = 0.0 by default.
LINX Reactance of the dummy series element used during power flow solutions; entered
in pu. LINX = 0.05 by default.
RMPCT Percent of the total Mvar required to hold the voltage at the bus controlled by the
shunt element of this FACTS device that are to be contributed by this shunt
element; RMPCT must be positive. RMPCT is needed only if REMOT specifies a
valid remote bus and there is more than one local or remote voltage controlling
device (plant, switched shunt, FACTS device shunt element, or VSC dc line
converter) controlling the voltage at bus REMOT to a setpoint, or REMOT is zero
but bus I is the controlled bus, local or remote, of one or more other setpoint mode
voltage controlling devices. RMPCT = 100.0 by default.
OWNER Owner number (1 through 9999). OWNER = 1 by default.
SET1, If MODE is 3, resistance and reactance respectively of the constant impedance,
SET2 entered in pu; if MODE is 4, the magnitude (in pu) and angle (in degrees) of the
constant series voltage with respect to the quantity indicated by VSREF; if MODE is
7 or 8, the real (Vd) and imaginary (Vq) components (in pu) of the constant series
voltage with respect to the quantity indicated by VSREF; for other values of MODE,
SET1 and SET2 are read, but not saved or used during power flow solutions.
SET1 = 0.0 and SET2 = 0.0 by default.
VSREF Series voltage reference code to indicate the series voltage reference of SET1 and
SET2 when MODE is 4, 7 or 8:
0 for sending end voltage
1 for series current.
VSREF = 0 by default.
REMOT Bus number, or extended bus name enclosed in single quotes (refer to Extended
Bus Names), of a remote Type 1 or 2 bus where voltage is to be regulated by the
shunt element of this FACTS device to the value specified by VSET. If bus REMOT
is other than a Type 1 or 2 bus, the shunt element regulates voltage at the sending
end bus to the value specified by VSET. REMOT is entered as zero if the shunt
element is to regulate voltage at the sending end bus and must be zero if the
sending end bus is a Type 3 (swing) bus. REMOT = 0 by default.
MNAME The name of the FACTS device that is the IPFC master device when this FACTS
device is the slave device of an IPFC (i.e., its MODE is specified as 6 or 8). MNAME
must be enclosed in single or double quotes if it contains any blanks or special char-
acters. MNAME is blank by default.

FACTS device data input is terminated with a record specifying a FACTS device number of zero.

FACTS Device Notes

PSS®E’s FACTS device model contains a shunt element that is connected between the sending
end bus and ground, and a series element connected between the sending and terminal end buses.

A static synchronous condenser (STATCON) or static compensator (STATCOM) is modeled by a

FACTS device for which the terminal end bus is specified as zero (i.e., the series element is
disabled).

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A unified power flow controller (UPFC) has both the series and shunt elements active, and allows
for the exchange of active power between the two elements (i.e., TRMX is positive). A static syn-
chronous series compensator (SSSC) is modeled by setting both the maximum shunt current limit
(SHMX) and the maximum bridge active power transfer limit (TRMX) to zero (i.e., the shunt element
is disabled).

An Interline Power Flow Controller (IPFC) is modeled by using two series FACTS devices. One
device of this pair must be assigned as the IPFC master device by setting its control mode to 5 or
7; the other must be assigned as its companion IPFC slave device by setting its control mode to 6
or 8 and specifying the name of the master device in its MNAME. In an IPFC, both devices have a
series element but no shunt element. Therefore, both devices typically have SHMX set to zero, and
VSET of both devices is ignored. Conditions at the master device define the active power exchange
between the two devices. TRMX of the master device is set to the maximum active power transfer
between the two devices, and TRMX of the slave device is set to zero.

Figure 1-15 shows the PSS®E FACTS control device model with its various setpoints and limits.

Each FACTS sending end bus must be a Type 1 or 2 bus, and each terminal end bus must be a
Type 1 bus. Refer to Section 6.3.16, FACTS Devices and Section 6.3.18, AC Voltage Control for
other topological restrictions and for details on the handling of FACTS devices during the power flow
solution activities.

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Program Operation Manual Switched Shunt Data

Figure 1-15. FACTS Control Device Setpoints and Limits

1.25 Switched Shunt Data

Automatically switched shunt devices may be represented on a network bus.


The switched shunt elements at a bus may consist entirely of blocks of shunt reactors (each Bi is a

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negative quantity), entirely of blocks of capacitor banks (each Bi is a positive quantity), or of both
reactors and capacitors.

Each network bus to be represented in PSS®E with switched shunt admittance devices must have
a switched shunt data record specified for it. The switched shunts are represented with up to eight
blocks of admittance, each one of which consists of up to nine steps of the specified block admit-
tance. Each switched shunt data record has the following format:

I, MODSW, ADJM, STAT, VSWHI, VSWLO, SWREM, RMPCT, ’RMIDNT’,

BINIT, N1, B1, N2, B2, ... N8, B8

where:

I Bus number, or extended bus name enclosed in single quotes (refer to Extended
Bus Names). No default allowed.
MODSW Control mode:
0 locked
1 discrete adjustment, controlling voltage locally or at bus SWREM
2 continuous adjustment, controlling voltage locally or at bus SWREM
3 discrete adjustment, controlling the reactive power output of the plant at bus SWREM
4 discrete adjustment, controlling the reactive power output of the VSC dc line converter
at bus SWREM of the VSC dc line for which the name is specified as RMIDNT
5 discrete adjustment, controlling the admittance setting of the switched shunt at bus
SWREM
6 discrete adjustment, controlling the reactive power output of the shunt element of the
FACTS device for which the name is specified as RMIDNT

MODSW = 1 by default.
ADJM Adjustment method:
0 steps and blocks are switched on in input order, and off in reverse input order; this
adjustment method was the only method available prior to PSS®E-32.0.
1 steps and blocks are switched on and off such that the next highest (or lowest, as
appropriate) total admittance is achieved.

ADJM = 0 by default.
STAT Initial switched shunt status of one for in-service and zero for out-of-service;
STAT = 1 by default.
VSWHI When MODSW is 1 or 2, the controlled voltage upper limit; entered in pu.
When MODSW is 3, 4, 5 or 6, the controlled reactive power range upper limit;
entered in pu of the total reactive power range of the controlled voltage controlling
device.
VSWHI is not used when MODSW is 0. VSWHI = 1.0 by default.
VSWLO When MODSW is 1 or 2, the controlled voltage lower limit; entered in pu.
When MODSW is 3, 4, 5 or 6, the controlled reactive power range lower limit;
entered in pu of the total reactive power range of the controlled voltage controlling
device.
VSWLO is not used when MODSW is 0. VSWLO = 1.0 by default.

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SWREM Bus number, or extended bus name enclosed in single quotes (refer to Extended
Bus Names), of the bus where voltage or connected equipment reactive power
output is controlled by this switched shunt.
When MODSW is 1 or 2, SWREM is entered as 0 if the switched shunt is to regulate
its own voltage; otherwise, SWREM specifies the remote Type 1 or 2 bus where
voltage is to be regulated by this switched shunt
When MODSW is 3, SWREM specifies the Type 2 or 3 bus where plant reactive
power output is to be regulated by this switched shunt. Set SWREM to I if the
switched shunt and the plant that it controls are connected to the same bus.
When MODSW is 4, SWREM specifies the converter bus of a VSC dc line where
converter reactive power output is to be regulated by this switched shunt. Set
SWREM to I if the switched shunt and the VSC dc line converter that it controls are
connected to the same bus.
When MODSW is 5, SWREM specifies the remote bus to which the switched shunt
for which the admittance setting is to be regulated by this switched shunt is
connected.
SWREM is not used when MODSW is 0 or 6. SWREM = 0 by default.
RMPCT Percent of the total Mvar required to hold the voltage at the bus controlled by bus I
that are to be contributed by this switched shunt; RMPCT must be positive. RMPCT
is needed only if SWREM specifies a valid remote bus and there is more than one
local or remote voltage controlling device (plant, switched shunt, FACTS device
shunt element, or VSC dc line converter) controlling the voltage at bus SWREM to a
setpoint, or SWREM is zero but bus I is the controlled bus, local or remote, of one or
more other setpoint mode voltage controlling devices. Only used if MODSW = 1 or
2. RMPCT = 100.0 by default.
RMIDNT When MODSW is 4, the name of the VSC dc line where the converter bus is speci-
fied in SWREM. When MODSW is 6, the name of the FACTS device where the
shunt element’s reactive output is to be controlled. RMIDNT is not used for other
values of MODSW. RMIDNT is a blank name by default.
BINIT Initial switched shunt admittance; entered in Mvar at unity voltage. BINIT = 0.0 by
default.
Ni Number of steps for block i (0 < Ni < 9). The first zero value of Ni or Bi is interpreted
as the end of the switched shunt blocks for bus I. Ni = 0 by default.
Bi Admittance increment for each of Ni steps in block i; entered in Mvar at unity
voltage. Bi = 0.0 by default.

Switched shunt data input is terminated with a record specifying a bus number of zero.

Switched Shunt Notes

BINIT needs to be set to its actual solved case value only when the network, as entered into the
working case via activity READ, is to be considered solved as read in, or when the device is to be
treated as locked (i.e., MODSW is set to zero or switched shunt adjustment is disabled during power
flow solutions).

The switched shunt elements at a bus may consist entirely of reactors (each Bi is a negative quan-
tity) or entirely of capacitor banks (each Bi is a positive quantity). In these cases, when ADJM is
zero, the shunt blocks are specified in the order in which they are switched on the bus; when ADJM
is one, the shunt blocks may be specified in any order.

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The switched shunt devices at a bus may be comprised of a mixture of reactors and capacitors. In
these cases, when ADJM is zero, the reactor blocks are specified first in the order in which they are
switched on, followed by the capacitor blocks in the order in which they are switched on; when
ADJM is one, the reactor blocks are specified first in any order, followed by the capacitor blocks in
any order.

In specifying reactive power limits for setpoint mode voltage controlling switched shunts (i.e., those
with MODSW of 1 or 2), the use of a very narrow admittance range is discouraged. The Newton-
Raphson based power flow solutions require that the difference between the controlling equip-
ment's high and low reactive power limits be greater than 0.002 pu for all setpoint mode voltage
controlling equipment (0.2 Mvar on a 100 MVA system base). It is recommended that voltage con-
trolling switched shunts have admittance ranges substantially wider than this minimum permissible
range.

When MODSW is 3, 4, 5 or 6, VSWLO and VSWHI define a restricted band of the controlled
device’s reactive power range. They are specified in pu of the total reactive power range of the con-
trolled device (i.e., the plant QMAX - QMIN when MODSW is 3, MAXQ - MINQ of a VSC dc line
converter when MODSW is 4, NiBiNjBj when MODSW is 5 where i are those switched shunt
blocks for which Bi is positive and j are those for which Bi is negative, and 2.*SHMX of the shunt
element of the FACTS device, reduced by the current corresponding to the bridge active power
transfer when a series element is present, when MODSW is 6). VSWLO must be greater than or
equal to 0.0 and less than VSWHI, and VSWHI must be less than or equal to 1.0. That is, the fol-
lowing relationship must be honored:

0.0 < VSWLO < VSWHI < 1.0

The reactive power band for switched shunt control is calculated by applying VSWLO and VSWHI
to the reactive power band extremes of the controlled plant or VSC converter. For example, with
MINQ of -50.0 pu and MAXQ of +50.0 pu, if VSWLO is 0.2 pu and VSWHI is 0.75 pu, then the reac-
tive power band defined by VSWLO and VSWHI is:

-50.0 + 0.2*(50.0 - (-50.0)) = -50.0 + 0.2*100.0 = -50.0 + 20.0 = -30.0 Mvar

through:

-50.0 + 0.75*(50.0 - (-50.0)) = -50.0 + 0.75*100.0 = -50.0 + 75.0 = +25.0 Mvar

The switched shunt admittance is kept in the working case and reported in output tabulations sep-
arately from the fixed bus shunt, which is entered on the fixed bus shunt data record (refer to Fixed
Bus Shunt Data).

Refer to Section 6.3.15, Switched Shunt Devices and Section 6.3.17, DC Lines and Switched Shunt
Adjustment for details on the handling of switched shunts during power flow solutions.

It is recommended that data records for switched shunts for which the control mode is 5 (i.e., they
control the setting of other switched shunts) be grouped together following all other switched shunt
data records. This practice will eliminate any warnings of no switched shunt at the specified remote
bus simply because the remote bus switched shunt record has not as yet been read.

Switched Shunt Example

Figure 1-16 shows the data record that may be specified to match the combination of switched ele-
ments on Bus 791. Note that the quantity shown as Load is entered as Load Data, and the fixed bus

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Program Operation Manual GNE Device Data

shunt indicated as B SHUNT and G SHUNT is entered as Fixed Bus Shunt Data.

791 1
I MODSW ADMIN STAT
1 1

Figure 1-16. Example Data Record for Combination of Switched Shunts

1.26 GNE Device Data

PSS®E accepts data for Generic Network Element (GNE) devices that are modeled in BOSL ".mac"
files. Each instance of a GNE device to be represented in PSS®E is specified in a GNE device data
record block. Each GNE device data record block has the following format:

’NAME’,’MODEL’,NTERM, BUS1, ...,BUSNTERM,NREAL,NINTG,NCHAR,

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STATUS, OWNER,NMETR

REAL1, ..., REALmin(10,NREAL) 

INTG1, ..., INTGmin(10,NINTG) 
CHAR1, ..., CHARmin(10,NCHAR)

where:

NAME The non-blank alphanumeric identifier assigned to this GNE device. Each GNE
device instance must have a unique NAME. NAME may be up to twelve characters
and may contain any combination of blanks, uppercase letters, numbers and
special characters. NAME must be enclosed in single or double quotes if it contains
any blanks or special characters. No default allowed.
MODEL The name of the BOSL model. NAME is the root name of the ".mac" file containing
the BOSL model. No default allowed.
NTERM The number of buses to which this instance of the model is connected. NTERM may
be either 1 or 2 for a variable admittance model, and must be 1 for a variable power
model and a variable current model. NTERM = 1 by default.
BUSi Bus number, or extended bus name enclosed in single quotes (refer to Extended
Bus Names). No default allowed.
NREAL Number of floating point data items required by model MODEL. NREAL must be
identical to the number required by the ".mac" file. NREAL = 0 by default.
NINTG Number of buses required in calculating the inputs required by model MODEL.
NINTG must be identical to the number required by the ".mac" file. NINTG = 0 by
default.
NCHAR Number of two-character identifiers (e.g., machine identifiers, circuit identifiers, etc.)
required in calculating the inputs required by model MODEL. NCHAR must be iden-
tical to the number required by the ".mac" file. NINTG = 0 by default.
STATUS Device status of one for in-service and zero for out-of-service; STATUS = 1 by
default.
OWNER Owner to which the device is assigned (1 through 9999). By default, OWNER is the
owner to which BUS1 is assigned (refer to Bus Data).
NMETR Bus number, or extended bus name enclosed in single quotes (refer to Extended
Bus Names), of the non-metered end bus. NMETR is used for GNE devices with
NTERM > 1. NMETR = BUSNTERM by default.
REALi NREAL floating point data items required by model MODEL. REALi = 0.0 by default.
Data items are entered 10 per line, with as many lines as required to supply NREAL
data items. If NREAL is 0, no record is specified.
INTGi NINTG bus numbers or extended bus names required by model MODEL. INTGi =
BUS1 by default.
Data items are entered 10 per line, with as many lines as required to supply NINTG
data items. If NINTG is 0, no record is specified.
CHARi NCHAR two-character identifiers required by model MODEL. CHARi = "1" by
default.
Data items are entered 10 per line, with as many lines as required to supply NCHAR
data items. If NCHAR is 0, no record is specified.

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GNE device data input is terminated with a record specifying a blank GNE device name or a GNE
device name of ’0’.

GNE devices are not recognized in all forms of analysis available in PSS®E. For example,
they are ignored in the fault analysis activities. Those analysis functions from which they are
excluded print an appropriate message if any in-service GNE devices are present in the working
case.

1.27 Induction Machine Data

Each network bus at which an induction machine is to be represented must be specified in at least
one induction machine data record. Multiple induction machines may be represented at a bus by
specifying more than one induction machine data record for the bus, each with a different machine
identifier.

Each induction machine data record has the following format:

I,ID,STAT,SCODE,DCODE,AREA,ZONE,OWNER,TCODE,BCODE,MBASE,RATEKV,
PCODE,PSET,H,A,B,D,E,RA,XA,XM,R1,X1,R2,X2,X3,E1,SE1,E2,SE2,IA1,IA2,
XAMULT

where:

I Bus number, or extended bus name enclosed in single quotes (refer to Extended
Bus Names). No default allowed.
ID One- or two-character uppercase non-blank alphanumeric machine identifier used
to distinguish among multiple induction machines at bus I. It is recommended that,
at buses for which a single induction machine is present, it be designated as having
the machine identifier 1. ID = 1 by default.
STAT Machine status of 1 for in-service and 0 for out-of-service. STAT = 1 by default.
SCODE Machine standard code.
=1, for NEMA
=2, for IEC
SCODE = 1 by default
DCODE Machine design code. Following are allowed machine design codes.
=0, for Custom design with equivalent circuit reactances specified
=1, for NEMA Design A
=2, for NEMA Design B / IEC Design N
=3, for NEMA Design C / IEC Design H
=4, for NEMA Design D
=5, for NEMA Design E
DCODE = 2 by default.
AREA Area to which the induction machine is assigned (1 through 9999). By default,
AREA is the area to which bus I is assigned (refer to Bus Data).
ZONE Zone to which the induction machine is assigned (1 through 9999). By default,
ZONE is the zone to which bus I is assigned (refer to Bus Data).

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OWNER Owner to which the induction machine is assigned (1 through 9999). By default,
OWNER is the owner to which bus I is assigned (refer to Bus Data).
TCODE Type of mechanical load torque variation.
=1, for the simple power law
=2, for the WECC model.
TCODE = 1 by default.
BCODE Machine base power code.
=1, for 1 for mechanical power (MW) output of the machine
=2, for apparent electrical power (MVA) drawn by the machine
BCODE = 1 by default.
MBASE Machine base power; entered in MW or MVA. This value is specified according to
BCODE, and could be either the mechanical rating of the machine or the electrical
input. It is necessary only that the per unit values entered for the equivalent circuit
parameters match the base power. MBASE = system base MVA by default.
RATEKV Machine rated voltage; entered in kV line-to-line, or zero to indicate that machine
rated voltage is assumed to be identical to the base voltage of bus I. RATEKV = 0.0
by default.
PCODE Scheduled power code
=1, for mechanical power (MW) output of the machine
=2, for electrical real power (MW) drawn by the machine.
PCODE = 1 by default.
PSET Scheduled active power for a terminal voltage at the machine of 1.0 pu of the
machine rated voltage; entered in MW. This value is specified according to PCODE,
and is either the mechanical power output of the machine or the real electrical
power drawn by the machine. The sign convention used is that PSET specifies
power supplied to the machine:
A positive value of electrical power means that the machine is operating as a motor;
similarly, a positive value of mechanical power output means that the machine is
driving a mechanical load and operating as a motor. No default allowed.
H Machine inertia; entered in per unit on MBASE base. H = 1.0 by default.
A, B, D, E Constants that describe the variation of the torque of the mechanical load with
speed. If TCODE is 1 (simple power law model), only D is used; if TCODE is 2
(WECC model), all of these constants are used. A = B = D = E = 1.0 by default.
RA Armature resistance, ra (> 0.0); entered in per unit on the power base MBASE and
voltage base RATEKV. RA = 0.0 by default.
XA Armature leakage reactance, Xa (> 0.0); entered in per unit on the power base
MBASE and voltage base RATEKV. XA = 0.0 by default.
XM Unsaturated magnetizing reactance, Xm (> 0.0); entered in per unit on the power
base MBASE and voltage base RATEKV. XM = 2.5 by default.
R1 Resistance of the first rotor winding ("cage"), r1 (> 0.0); entered in per unit on the
power base MBASE and voltage base RATEKV. R1 = 999.0 by default.
X1 Reactance of the first rotor winding ("cage"), X1 (> 0.0); entered in per unit on the
power base MBASE and voltage base RATEKV. X1 = 999.0 by default.

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R2 Resistance of the second rotor winding ("cage"), r2 (> 0.0); entered in per unit on
the power base MBASE and voltage base RATEKV. R2 = 999.0 by default.
X2 Reactance of the second rotor winding ("cage"), X2 (> 0.0); entered in per unit on
the power base MBASE and voltage base RATEKV. X2 = 999.0 by default.
X3 Third rotor reactance, X3 (> 0.0); entered in per unit on the power base MBASE and
voltage base RATEKV. X3 = 0.0 by default.
E1 First terminal voltage point from the open circuit saturation curve, E1 (> 0.0);
entered in per unit on RATEKV base. E1 = 1.0 by default.
SE1 Saturation factor at terminal voltage E1, S(E1). SE1 = 0.0 by default.
E2 Second terminal voltage point from the open circuit saturation curve, E2 (> 0.0);
entered in per unit on RATEKV base. E2 = 1.2 by default.
SE2 Saturation factor at terminal voltage E2, S(E2). SE2 = 0.0 by default.
IA1,IA2 Stator currents in PU specifying saturation of the stator leakage reactance, XA.
IA1=IA2=0.0 by default.
XAMULT Multiplier for the saturated value. Allowed value 0 to 1.0. XAMULT=1 by default.

Induction machine data input is terminated with a record specifying a bus number of zero.

Machine Electrical Data

The positive sequence steady state equivalent circuit for the induction machine is shown in
Figure 1-17.

Figure 1-17. Induction Machine Equivalent Circuit

The machine model is described by eight electrical elements: three resistive and five inductive.
Values are specified in per unit on the base power, MBASE, and rated voltage, RATEKV, which are
also specified on the data record.

The left side of the circuit is the machine armature: ra is the armature resistance and Xa is the arma-
ture leakage reactance. The armature and the rotor are linked through the magnetizing reactance
Xm; the unsaturated value of the mutual reactance is specified.

The rotor is described by two parallel resistance and reactance branches, r1, X1 and r2, X2, that
represent the "cages" or windings in the rotor. To model a single cage machine, the resistance and

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reactance of the second of these parallel branches must both be specified as 999.0; i.e., to model
a single cage machine, specify r2 = X2 = 999.0 on the data record.

The reactance X3 is included to allow a more general model.

The mutual reactance Xm saturates. The saturation curve is for the induction machine operating
with no load. Two points on the saturation curve must be specified. These are normally chosen such
that E1 is near the "knee" of the saturtion curve and E2 is near its ceiling. Saturation is neglected if
E1  S(E1) = 0.0; therefore, to neglect saturation, specify either E1 or SE1 as 0.0.

If a non-zero machine design code (DCODE) value is specified, all data items from RA to the end
of the record are ignored, and pre-programmed machine electrical and saturation data values are
assigned to the machine. If you wish to modify any of these data items after they have been
assigned, you may change the machine design code to 0 (custom).

Load Mechanical Data

Five data items (TCODE, A, B, D and E) are used to describe how the torque of the mechanical
load varies with speed.When TCODE is 1, a simple power law is applied that uses the constant
specified as D. The equation is
Tload = Tload0 (1-s)D
(1-s0)D

where Tload0 is the load torque and S0 is the slip at a terminal voltage of 1.0 pu.

The WECC model applies the following equations:

Tload = Tload0 [A(1-s)2+B(1-s)+D(1-s)E+C0] WECC Model

C0=1-A(1-s0)2-B(1-s0)+D(1-s0)E

1.28 Substation Data

Each substation to be represented in PSS®E is introduced by reading a substation data record
block. Each substation block consists of:

• A substation data record.

• Several node data records.
• Several substation switching device data records.
• Several equipment terminal data records.

1.28.1 Substation Data Record

The first record in each substation block is a substation data record. Exactly one such record is
specified in each substation block. Each substation data record has the following format:

IS, NAME, LATI, LONG, SGR

IS Substation number (1 through 99999). No default allowed.

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NAME Substation name, NAME may be up to forty characters and may

contain any combination of blanks, uppercase letters, numbers and
special characters. NAME must be enclosed in single or double
quotes if it contains any blanks or special characters. NAME is forty
blanks by default.
LATI Substation latitude in degrees (-90.0 to 90.0). It is positive for North
and negative for South, 0.0 by default.
LONG Substation longitude in degrees. (-180.0 to 180.0). It is positive for
East and negative for West, 0.0 by default.
SRG Substation grounding DC resistance in ohms.

Substation data input is terminated with a record specifying a substation number of zero.

1.28.2 Node Data

The substation data record is followed by substation node data. Each node in the substation is spec-
ified in a node data record. Each node data record has the following format:

NI, NAME, I, STATUS

NI Node number (1 through 999). No default allowed.

NAME Node name, NAME may be up to 40 characters and may contain any
combination of blanks, uppercase letters, numbers and special
characters. NAME must be enclosed in single or double quotes if it
contains any blanks or special characters. NAME is 40 blanks by
default.
I Electrical Bus number (1 through 999997) in bus branch model. The
electrical bus represents this node NI and others that are connected
by closed switching devices. No default allowed.
STATUS Node status. One for in-service and zero for out-of-service. STATUS =
1 by default.

Node data input for this substation is terminated with a record specifying a node number of zero.

1.28.3 Station Switching Device Data

The node data records are followed by substation switching device data. Each station switching
device in the substation is specified in a station switching device data record. Each station switching
device data record has the following format:

NI,NJ,CKTID,NAME,TYPE,STATUS,NSTAT,X,RATE1,RATE2,RATE3

NI From node number (1 through 999). The from node must be in the
sub- station IS. No default allowed.
NJ To node number (1 through 999). The to node must be in the
substation IS. No default allowed.
CKTID Two-character uppercase non-blank alphanumeric switching device
identifier; CKT = 1 by default.

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NAME Switching device name, NAME may be up to 40 characters and may

contain any combination of blanks, uppercase letters, numbers and
special characters. NAME must be enclosed in single or double
quotes if it contains any blanks or special characters. NAME is 40
blanks by default.
TYPE Switching device type
1 - Generic connector
2 - Circuit breaker
3 - Disconnect switch
STATUS Switching device status. one for close and zero for open; STATUS = 1
by default.
NSTAT Switching device normal status. one for close and zero for open;
NSTAT = 1 by default.
X Switching device reactance; entered in pu. A non-zero value of X must
be entered for each switching device. X = 0.0001 by default.
RATE1 First rating; entered in either MVA or current expressed as MVA.
RATE2 Second rating; entered in either MVA or current expressed as MVA.
RATE3 Third rating; entered in either MVA or current expressed as MVA.

Station switching device data input for this substation is terminated with a record specifying a from
node number of zero.

1.28.4 Equipment Terminal Data

The substation switching device data records are followed by equipment terminal data. Equipment
items that are connected to substation buses are specified in equipment terminal data records. The
following paragraphs describe the record formats of the various types of terminal equipment that
may be specified. Within the set equipment terminal data records specified for a substation, records
may be specified in any order.

Equipment terminal data input for this substation is terminated with a record specifying a bus
number of zero.

Load Terminal Data

Each load terminal data record has the following format:

I, NI, 'L', ID

I bus number. No default allowed.

NI node number (1 through 999). If the electrical bus has node breaker
model, in other words it represents a set of nodes in a substation, the
node must be one node in the set and indicates the connections of the
load within the substation. If the electrical bus has no node breaker
model, it is zero. No default allowed.
L Specifies that the record contains terminal information for a Load

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ID One- or two-character uppercase non-blank alphanumeric load identi-

fier used to distinguish among multiple loads at bus I. It is
recommended that, at buses for which a single load is present, the
load be designated as having the load identifier 1. ID = 1 by default.

Fixed Shunt Terminal Data

Each fixed shunt terminal data record has the following format:

I, NI, 'F', ID

I bus number. No default allowed.

NI node number (1 through 999). If the electrical bus has node breaker
model, in other words it represents a set of nodes in a substation, the
node must be one node in the set and indicates the connections of the
shunt within the substation. If the electrical bus has no node breaker
model, it is zero. No default allowed.
F Specifies that the record contains terminal information for a Fixed
Shunt
ID One- or two-character uppercase non-blank alphanumeric shunt
identifier used to distinguish among multiple shunts at bus I. It is
recommended that, at buses for which a single shunt is present, the
shunt be designated as having the shunt identifier 1. ID = 1 by default.

Machine Terminal Data

Each machine terminal data record has the following format:

I, NI, 'M', ID

I bus number. No default allowed.

NI node number (1 through 999). If the electrical bus has node breaker
model, in other words it represents a set of nodes in a substation, the
node must be one node in the set and indicates the connections of the
machine within the substation. If the electrical bus has no node
breaker model, it is zero. No default allowed.
M Specifies that the record contains terminal information for a Machine
ID One- or two-character uppercase non-blank alphanumeric machine
identifier used to distinguish among multiple machines at bus I. It is
recommended that, at buses for which a single machine is present, the
machine be designated as having the machine identifier 1. ID = 1 by
default.

Branch and two winding Transformer Terminal Data

Each non-transformer branch and two-winding transformer terminal data record has the following
format:

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I,NI,'B',J,CKTID 
or: I,NI,'2',J,CKTID

I From bus number. No default allowed.

NI From node number (1 through 999). If the electrical from bus has node
breaker model, in other words it represents a set of nodes in a substa-
tion, the from node must be one node in the set and indicates the
connections of branch within the substation. If the electrical from bus
has no node breaker model, it is zero. No default allowed.
B or 2 Specifies that the record contains terminal information for a non-
transformer or two-winding transformer
J To bus number. No default allowed.
CKTID two-character uppercase non-blank alphanumeric switching device
identifier; CKT = 1 by default.

Three winding Transformer Terminal Data

Each three winding transformer terminal data record has the following format:

I, NI, '3', J, K, CKTID

I From bus number. No default allowed.

NI From node number (1 through 999). If the electrical from bus I has
node breaker model, in other words it represents a set of nodes in a
substa- tion, the from node must be one node in the set and indicates
the connections of branch within the substation. If the electrical from
bus has no node breaker model, it is zero. No default allowed.
3 Specifies that the record contains terminal information for a three-
winding transformer
J To bus number. No default allowed.
K To bus number. No default allowed.
CKTID two-character uppercase non-blank alphanumeric switching device
identifier; CKT = 1 by default.

Switched Shunt Terminal Data

Each switched shunt terminal data record has the following format:

I, NI, 'S'

I bus number. No default allowed.

NI node number (1 through 999). If the electrical bus has node breaker
model, in other words it represents a set of nodes in a substation, the
node must be one in the set and indicates the connections of the
switched shunt within the substation. If the electrical bus has no node
breaker model, it is zero. No default allowed.
S Specifies that the record contains terminal information for a switched
shunt

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Program Operation Manual End of Data Indicator

1.29 End of Data Indicator

It is good practice to end the Power Flow Raw Data File with a Q Record. Then, if new data cate-
gories are introduced in a point release of PSS®E, no modification of the file is required.

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 Chapter 2
Sequence Data File Contents

Chapter 2 - Sequence Data File Contents

2.1 Overview
The input stream to activity RESQ is a Sequence Data File containing 11 groups of records with
each group specifying a particular type of sequence data required for fault analysis work (see
Figure 2-1). Any piece of equipment for which sequence data is to be entered in activity RESQ must
be represented as power flow data in the working case. That is, activity RESQ will not accept data
for a bus, generator, branch, switched shunt or fixed shunt not contained in the working case.

All data is read in free format with data items separated by a comma or one or more blanks. Each
category of data except the change code is terminated by a record specifying an I value of zero.
Termination of all data is indicated by a value of Q.

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Change Code Program Operation Manual

Change Code

System Wide Data

Generator Sequence Data

Load Sequence Data

Zero Sequence Non-Transformer Branch Data

Zero Sequence Mutual Impedance Data

Zero Sequence Transformer Data

Zero Sequence Switched Shunt Data

Zero Sequence Fixed Shunt Data

Induction Machine Sequence Data

Non-Conventional Source Fault Contribution Data

Q Record

Figure 2-1. Sequence Data Input Structure

2.2 Change Code

The first record in the Sequence Data File contains two data items as follows:

IC, REV

IC = 0 Indicates the initial input of sequence data for the network contained in the working
case. All buses, generators, branches, switched shunts and fixed shunts for which
no data record is entered in a given category of data have the default values
assigned for those data items.
IC=0 by default.
IC = 1 Indicates change case input of sequence data for the network contained in the
working case. All buses, generators, branches, switched shunts and fixed shunts for
which no data record is entered in a given category of data have those data items
unchanged; i.e., they are not set to the default values.
REV PSS®E revision number. REV=Current revision by default.

The use of the change case mode in activity RESQ is identical to its use in activity READ: for the
addition of equipment to the working case (e.g., to add a zero sequence mutual coupling to the

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Program Operation Manual System Wide Data

working case). It is not valid to set IC to one for the initial execution of activity RESQ for the network
in the working case; in this case, an appropriate message is printed and activity RESQ continues
its execution as if IC had been specified as zero.

2.3 System Wide Data

Through the system-wide data category, data that pertains to the case as a whole (rather than to
individual equipment items) may be included in the Sequence Data File to allow convenient transfer
of it with the case. Records may be included that define:

• Short Circuit Output Report Format.

• Metal Var Oxide (MOV) Iteration Options.
• Short Circuit Model.
Generally, each record specified in the System-Wide Data category begins with a NAME that
defines the type of data specified on the record. The formats of the various records are described
in the following paragraphs.

RPTFORMAT Record

The Short Circuit Output Report Format record begins with the name RPTFORMAT and contains
unit and co-ordinates option for reporting current, voltage and Thevenin impedance. Using keyword
input, any or all of the following report format parameters may be specified:

AMPOUT = 0, Current and Voltages in PU) (default)

= 1, Current in Amperes and Voltages in kV

POLROU = 0, Currents and Voltages in Rectangular co-ordinates (default)

= 1, Currents and Voltages in Polar co-ordinates

AMPOUTZ = 0, Thevenin Impedance in PU (default)

= 1, Thevenin Impedance in ohms

POLROUZ = 0, Thevenin Impedance in Rectangular co-ordinates (default)

= 1, Thevenin Impedance in Polar co-ordinates

Those RPTFORMAT parameters that are specified may be entered in any order. The following is
an example of this record:

RPTFORMAT, AMPOUT=0, POLROU=0, AMPOUTZ=0, POLROUZ=0

MOV Record

The Metal Var Oxide (MOV) Iteration Options record begins with the name MOV and contains lin-
earized MOV model iteration parameters used by short circuit calculation methods. Using keyword
input, any or all of the following MOV iteration parameters may be specified:

ITERATIONS Maximum number of iterations (default=20)

TOLERANCE Tolerance (default=0.01)

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MOVALPHA Acceleration factor (default=0.3)

Those parameters that are specified may be entered in any order. The following is an example of
this record:

MOV, ITERATIONS=20, TOLERANCE=0.01, MOVALPHA=0.3

SCMODEL Record

The Short Circuit Model Options record begins with the name SCMODEL and contains fault anal-
ysis modeling option setting. Using keyword input, SCMODEL parameters may be specified:

SCNRML = 0, center tapped two-phase modeling

= 1, Normal three-phase modeling (default)

The following is an example of this record:

SCMODEL, SCNRML=1

2.4 Generator Sequence Data

Each network bus to be represented as a generator bus (i.e., as a current source) in the unbalanced
analysis activities must have sequence generator impedances entered into the PSS®E working
case for all in-service machines at the bus.

Each generator sequence impedance data record has the following format:

I, ID, ZRPOS, ZXPPDV, ZXPDV, ZXSDV, ZRNEG, ZXNEGDV, ZR0, ZX0DV, CZG, ZRG, ZXG,
REFDEG

I Bus number; bus I must be present in the working case as a generator bus.
ID One or two character machine identifier of the machine bus I for which the data is
specified by this record. ID=1 by default.
ZRPOS Generator positive sequence resistance; entered in pu on machine base (i.e., on
bus voltage base and MBASE). ZRPOS = ZR (source resistance in raw data) by
default.
ZXPPDV Generator positive sequence saturated subtransient reactance; entered in pu on
machine base (i.e., on bus voltage base and MBASE). ZXPPDV = ZX (source
reactance in raw data) by default.
ZXPDV Generator positive sequence saturated transient reactance; entered in pu on
machine base (i.e., on bus voltage base and MBASE). ZXPDV = ZXPPDV by
default.
ZXSDV Generator positive sequence saturated synchronous reactance; entered in pu on
machine base (i.e., on bus voltage base and MBASE). ZXSDV = ZXPPDV by
default.
ZRNEG Generator negative sequence resistance; entered in pu on machine base (i.e., on
bus voltage base and MBASE). ZRNEG = ZRPOS by default.
ZXNEGDV Generator negative sequence saturated reactance; entered in pu on machine base
(i.e., on bus voltage base and MBASE). ZXNEGDV = ZXPPDV by default.

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ZR0 Generator zero sequence resistance; entered in pu on machine base (i.e., on bus
voltage base and MBASE). ZR0 = ZRPOS by default.
ZX0DV Generator zero sequence saturated reactance; entered in pu on machine base
(i.e., on bus voltage base and MBASE). ZX0DV = ZXPPDV by default.
CZG Units of grounding impedance (ZRG and ZXG) values, = 1 for pu (on bus voltage
base and MBASE), = 2 for Ohms
ZRG Generator grounding resistance; entered in pu on machine base (i.e., on bus
voltage base and MBASE) when CZG=1 or in ohms when CZG=2. ZRG = 0.0 by
default.
ZXG Generator grounding reactance; entered in pu on machine base (i.e., on bus
voltage base and MBASE) when CZG=1 or in ohms when CZG=2. ZXG = 0.0 by
default.
REFDEG Generator Reference Angle; entered in degrees. REFDEG = 0.0 by default.
This angle is used only when fault calculations with for "FLAT" voltage profile is
selected.

Throughout this Manual, the complex positive sequence generator impedance used in fault analysis
will be referred to as ZPOS. The real component of ZPOS is always ZRPOS. Its imaginary compo-
nent is either ZXPPDV, ZXPDV or ZXSDV, according to the selection made in selecting the fault
analysis calculation activity. Similarly, the negative sequence generator impedance, ZNEG, is
ZRNEG + j ZXNEGDV, and the zero sequence generator impedance, ZZERO, is ZR0 + j ZX0DV.

During the initial input of sequence data (i.e., IC = 0 on the first data record), any machine for which
no data record of this category is entered has its positive sequence resistance set to ZR (the real
component of ZSORCE), and all three positive sequence reactances set to ZX (the imaginary com-
ponent of ZSORCE). ZSORCE is the generator impedance entered in activities READ, Section
Activity, TREA, RDCH, and MCRE; it is used in switching studies and dynamic simulations (refer to
Generator Data).

In subsequent executions of activity RESQ (i.e., IC = 1 on the first data record), any machine for
which no data record of this category is entered has its positive sequence generator impedance
values unchanged. Note that the generator positive sequence impedance values entered in activity
RESQ for fault analysis purposes is not necessarily the same as the generator impedance
(ZSORCE) used in dynamics, and that it does not overwrite ZSORCE. That is, the two different sets
of positive sequence impedance data are specified in the working case simultaneously at different
locations.

During the initial input of sequence data (i.e., IC = 0 on the first data record), any machine for which
no data record of this category is entered has its negative sequence generator impedance ZNEG
set equal to ZRPOS + j ZXPPDV. In subsequent executions of activity RESQ (i.e., IC = 1 on the first
data record), any machine for which no data record of this category is entered has its negative
sequence generator impedance unchanged.

For those machines at which the step-up transformer is represented as part of the generator data
(i.e., XTRAN is non-zero), ZZERO is not used and, in the fault analysis activities, the step-up trans-
former is assumed to be a delta wye transformer. Refer to Modeling of Generator Step-Up
Transformers (GSU).

For those machines that do not include the step-up transformer as part of the generator data (i.e.,
XTRAN is zero), a zero sequence impedance of zero results in the machine being treated as an
open circuit in the zero sequence.

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During the initial input of sequence data (i.e., IC = 0 on the first data record), any machine for which
no data record of this category is entered has its zero sequence generator impedance ZZERO set
equal to ZRPOS + j ZXPPDV. In subsequent executions of activity RESQ (i.e., IC = 1 on the first
data record), any machine for which no data record of this category is entered has its zero sequence
generator impedance unchanged.Generator sequence impedance data input is terminated with a
record specifying a bus number of zero.

Figure 2-2 shows generator representation in sequence networks.

ZRPOS+jZXPPDV or
ZRPOS+jZXPDV or ZRNEG+jZXNEGDV ZR0+jZX0DV
ZRPOS+jZXSDV
+
Ea 3(ZRG+jZXG)
-
Reference Reference
(a) Positive Sequence (b) Negative Sequence (c) Zero Sequence

Figure 2-2. Figure - Generator Sequence Networks

PSS®E calculates pu grounding impedance from ohm as below:

MBASE
ZRG + jZXG inPU = Z RG + jZ XG in ohm  ----------------------------
2
BASEKV

2.5 Load Sequence Data

Exceptional negative sequence loads (i.e., loads that, in the negative sequence, differ from the pos-
itive sequence loads) and zero sequence loads are entered into the working case in load sequence
data records in the Sequence Data File. Each load negative and zero sequence data record has the
following format:

I, ID, PNEG, QNEG, GRDFLG, PZERO, QZERO

I Bus number, bus I must be present in the working case.

ID One or two character load identifier of the load at bus I for which the data is
specified by this record. ID=1 by default.
PNEG Active component of negative sequence load; entered in MW at one per unit
voltage. If PNEG=0 or is not specified, PNEG = positive sequence load MW.
QNEG Reactive component of negative sequence load; entered in MVAR at one per unit
voltage. If QNEG=0 or is not specified, QNEG = positive sequence load MVAR.
GRDFLG Grounding flag; 1 for grounded loads and 0 for ungrounded loads. GRDFLG=0 by
default.

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Program Operation Manual Zero Sequence Non-Transformer Branch Data

PZERO Active component of zero sequence load; entered in MW at 1 pu voltage. If

PZERO is non-zero and GRDFLG=1, PZERO is modelled. If GRDFLG=0, PZERO
is ignored. PZERO=0 by default.
QZERO Reactive component of zero sequence load; entered in MVAR at 1 pu voltage. If
QZERO is non-zero and GRDFLG=1, QZERO is modelled. If GRDFLG=0,
QZERO is ignored. QZERO=0 by default.

For any bus where no load sequence data record is specified, or PNEG and QNEG are both spec-
ified as zero, the load elements are assumed to be equal in the positive and negative sequence
networks. For any bus where no load sequence data record is specified, or PZERO and QZERO
are both specified as zero, or GRDFLG is specified as zero (i.e., an ungrounded load), no load com-
ponent is represented in the zero sequence.

The user is advised to exercise caution in specifying negative and zero sequence loads. In the fault
analysis calculations, constant power and constant current loads are converted to constant admit-
tance at the pre-fault voltage. Further, when positive sequence loads are changed, either directly
by the user or by activities such as SCAL, it may be appropriate to change previously specified neg-
ative and zero sequence loads. It is the user’s responsibility to ensure that the positive sequence
loading data, as contained in the working case, is coordinated with the specified negative and zero
sequence load data.

Load sequence data input is terminated with a record specifying a bus number of zero.

2.6 Zero Sequence Non-Transformer Branch Data

Zero sequence non-transformer branch parameters are entered into the working case in zero
sequence non-transformer branch data records in the Sequence Data File. Each zero sequence
branch data record has the following format:

I, J, ICKT, RLINZ, XLINZ, BCHZ, GI, BI, GJ, BJ, IPR, SCTYP

where:

I Bus number of one end of the branch.

J Bus number of the other end of the branch.
ICKT One- or two-character branch circuit identifier; a non-transformer branch with circuit
identifier ICKT between buses I and J must be in the working case. ICKT = 1 by
default.
RLINZ Zero sequence branch resistance; entered in pu on system base MVA and bus
voltage base. RLINZ = 0.0 by default.
XLINZ Zero sequence branch reactance; entered in pu on system base MVA and bus
voltage base. Any branch for which RLINZ and XLINZ are both 0.0 is treated as
open in the zero sequence network. XLINZ must be negative for a series capacitor
branch. XLINZ = 0.0 by default.
BCHZ Total zero sequence branch charging susceptance; entered in pu. BCHZ = 0.0 by
default.
GI,BI Complex zero sequence admittance of the line connected shunt at the bus I end of
the branch; entered in pu. GI + jBI = 0.0 by default.
GJ,BJ Complex zero sequence admittance of the line connected shunt at the bus J end of
the branch; entered in pu. GJ + jBJ = 0.0 by default.

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Zero Sequence Mutual Impedance Data Program Operation Manual

IPR MOV rated current for a series capacitor branch; entered in kA. It must be positive
IPR=0.0 bye default
SCTYP MOV Protection Mode
0 for normal branch (i.e., not a MOV protected branch)
1 for MOV Protection enabled
2 for MOV Protection disabled
3 for Spark Gap Protection enabled (information only, not used in any calculations)
SCTPY=0 by default

The zero sequence network is assumed to be a topological subset of the positive sequence net-
work. That is, it may have a branch in every location where the positive sequence network has a
branch, and may not have a branch where the positive sequence network does not have a branch.
The zero sequence network does not need to have a branch in every location where the positive
sequence network has a branch.

A branch treated as a zero impedance line in the positive sequence (refer to Zero Impedance Lines)
is treated in the same manner in the zero sequence, regardless of its specified zero sequence
impedance.

During the initial input of sequence data (i.e., IC = 0 on the first data record), any non-transformer
branch for which no data record of this category is entered is treated as open in the zero sequence
network (i.e., the zero sequence impedance is set to zero). In subsequent executions of activity
RESQ (i.e., IC = 1 on the first data record), any branch for which no data record of this category is
entered has its zero sequence branch data unchanged.

Zero sequence branch data input is terminated with a record specifying a from bus number of zero.

2.7 Zero Sequence Mutual Impedance Data

Data describing mutual couplings between branches in the zero sequence network are entered into
the working case in zero sequence mutual impedance data records in the Sequence Data File.
Each zero sequence mutual impedance data record has the following format:

I, J, ICKT1, K, L, ICKT2, RM, XM, BIJ1, BIJ2, BKL1, BKL2

where:

I Bus number of one end of the first branch.

J Bus number of the other end of the first branch.
ICKT1 One- or two-character branch circuit identifier of the first branch; a non-transformer
branch with circuit identifier ICKT1 between buses I and J must be in the working
case. ICKT1 = 1 by default.
K Bus number of one end of the second branch.
L Bus number of the other end of the second branch.
ICKT2 One- or two-character branch circuit identifier of the second branch; a non-trans-
former branch with circuit identifier ICKT2 between buses K and L must be in the
working case. ICKT2 = 1 by default.
RM,XM Branch-to-branch mutual impedance coupling circuit ICKT1 from bus I to bus J with
circuit ICKT2 from bus K to bus L; entered in pu. No default is allowed.

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Program Operation Manual Zero Sequence Mutual Impedance Data

BIJ1 Starting location of the mutual coupling along circuit ICKT1 from bus I to bus J rela-
tive to the bus I end of the branch; entered in per unit of total line length. BIJ1 = 0.0
by default.
BIJ2 Ending location of the mutual coupling along circuit ICKT1 from bus I to bus J rela-
tive to the bus I end of the branch; entered in per unit of total line length. BIJ2 = 1.0
by default.
BKL1 Starting location of the mutual coupling along circuit ICKT2 from bus K to bus L rela-
tive to the bus K end of the branch; entered in per unit of total line length.
BKL1 = 0.0 by default.
BKL2 Ending location of the mutual coupling along circuit ICKT2 from bus K to bus L rela-
tive to the bus K end of the branch; entered in per unit of total line length.
BKL2 = 1.0 by default.

The following rules must be observed in specifying mutual impedance data:

• The maximum number of zero sequence mutual couplings that may be entered at the
standard size levels of PSS®E is defined in Table 3-1 Standard Maximum PSS®E Pro-
gram Capacities.
• The polarity of a mutual coupling is determined by the ordering of the bus numbers
(I,J,K,L) in the data record. The dot convention applies, with the from buses (I and K)
specifying the two dot ends of the coupled branches.
• RM+jXM specifies the circuit-to-circuit mutual impedance, given the polarity implied by
I and K.
• The geographical B factors are required only if one or both of the two mutually coupled
lines is to be involved in an unbalance part way down the line, and only part of the
length of one or both of the lines is involved in the coupling. (Note that the default
values of the B factors result in the entire length of the first line coupled to the entire
length of the second line.)
• The values of the B factors must be between zero and one inclusive; they define the
portion of the line involved in the coupling.
• BIJ1 must be less than BIJ2, and BKL1 must be less than BKL2.
• Mutuals involving transformers or zero impedance lines are ignored by the fault anal-
ysis solution activities.
The following figure schematically illustrates a mutual coupling with BIJ1 = 0.0, BIJ2 = 0.4,
BKL1 = 0.0 and BKL2 = 1.0 (the first 40% of the first line coupled with the entire second line).

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100 miles

40 miles 60 miles

40 miles

As a second example, BIJ1 = 0.6, BIJ2 = 1.0, BKL1 = 0.0 and BKL2 = 0.6 (last 40% of the first line
coupled with the first 60% of the second line) might be depicted as follows:

100 miles

60 miles 40 miles

26.67
40 miles miles

66.67 miles

Zero sequence mutual impedance data input is terminated with a record specifying a from bus
number of zero.

2.8 Zero Sequence Transformer Data

Zero sequence transformer parameters are entered into the working case in zero sequence trans-
former data records in the Sequence Data File. Each transformer data record has one of the
following formats:

For two-winding transformers:

I,J,K,ICKT,CZ0,CZG,CC,RG1,XG1,R01,X01,RG2,XG2,R02,X02,RNUTRL,XNUTRL

For three-winding transformers:

I,J,K,ICKT,CZ0,CZG,CC,RG1,XG1,R01,X01,RG2,XG2,R02,X02,
RG3,XG3,R03,X03,RNUTRL,XNUTRL

Notations used in Zero Sequence Networks

Z01=R01+jX01 Z02=R02+jX02 Z03=R03+jX03

Zg1=RG1+jXG1 Zg2=RG2+jXG2 Zg3=RG3+jXG3

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Program Operation Manual Zero Sequence Transformer Data

Znutrl=RNUTRL+jXNUTRL

I Bus number of the bus to which a winding of the transformer is connected.

J Bus number of the bus to which another winding of the transformer is connected.
K Bus number of the bus to which another winding of the transformer is connected.
Zero is used to indicate that no third winding is present (i.e., that a two-winding
transformer is being specified). K = 0 by default.
ICKT One- or two-character transformer circuit identifier; a transformer with circuit identi-
fier ICKT between buses I and J (and K if K is non-zero) must be in the working
case. ICKT = 1 by default.
CZ0 The non-grounding impedance data I/O code defines the units in which the
impedance values Z01, Z02 and Z03 are specified. In specifying these impedances,
the winding base voltage values are always the nominal winding voltages (NOMV1,
NOMV2 and NOMV3) that are specified on the third, fourth and fifth records of the
Transformer Data block in the Power Flow Raw Data File; see Transformer Data for
more details. If no value for NOMVn is specified, the winding "n" voltage base is
assumed to be identical to the winding "n" bus base voltage.
Legacy Connection Codes
For those connection codes that existed prior to PSS®E-33, CZ0 must be specified
as 1. For two-winding transformers, these are connection codes 1 through 9; for
three-winding transformers, these are connection codes 1 through 6, as well as the
three digit connection codes where each digit refers to one of the two-winding
connection codes 1 through 7 that is to be applied to one of the three windings of
the transformer.
For all two-winding transformers with legacy connection codes, Z01 is specified in
per unit on system MVA base and winding voltage base; for two-winding
transformers with connection code 9, Z02 is specified in per unit on system MVA
base and winding 2 voltage base.
For all three-winding transformers with legacy connection codes, Z01, Z02 and Z03
are specified in per unit on system MVA base and winding "n" voltage base.
Connection Codes Introduced in PSS®E-33
For all two-digit connection codes for two- and three-winding transformers, CZ0
may be specified as one of the following values:
1 for per unit on system MVA base and winding "n" voltage base
2 for per unit on a specified MVA base and winding "n" voltage base
These are the same units dictated by CZ values 1 and 2 on the transformer data
record of the Power Flow Raw Data File.

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CZG The grounding impedance data I/O code defines the units in which the impedance
values Zg1, Zg2, Zg3 and Znutrl are specified. In specifying these impedances, the
winding base voltage values are always the nominal winding voltages (NOMV1,
NOMV2 and NOMV3) that are specified on the third, fourth and fifth records of the
Transformer Data block in the Power Flow Raw Data File. If no value for NOMVn is
specified, the winding "n" voltage base is assumed to be identical to the winding "n"
bus base voltage.
Legacy Connection Codes
For those connection codes that existed prior to PSS®E-33, CZG must be specified
as 1. For two-winding transformers, these are connection codes 1 through 9; for
three-winding transformers, these are connection codes 1 through 6, as well as the
three digit connection codes.
For two-winding transformers with legacy connection codes 2, 3 and 9, Zg1 is
specified in per unit on system MVA base and winding voltage base. For two-
winding transformers with connection codes 5 through 8, Zg1 is specified in per unit
on system MVA base and winding voltage base. For two-winding transformers with
connection code 8, Zg2 is specified in per unit on system MVA base and winding 2
voltage base.
For three-winding transformers with legacy connection code 1, Zg1 is specified in
per unit on system MVA base and winding 1 voltage base. For three-winding
transformers with legacy connection code 5, Zg2 is specified in per unit on system
MVA base and winding 2 voltage base.
Connection Codes Introduced in PSS®E-33
For all two-digit connection codes for two- and three-winding transformers, CZG
may be specified as one of the following values:
1 for per unit on system MVA base and winding voltage base
2 for per unit on a specified MVA base and winding voltage base
For three winding transformers, Zg1 is on SBASE12, Zg2 on SBASE23, Zg3 on
SBASE31, and Znutrl on SABSE12.
3 for ohms
For CZG values of 1 and 2, these are the same units dictated by CZ values 1 and 2
on the transformer data record of the Power Flow Raw Data File.

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Program Operation Manual Zero Sequence Transformer Data

CC Winding connection code indicating the connections and ground paths to be used in
modeling the transformer in the zero sequence network.
For a two-winding transformer, valid values are 1 through 9 and 11 through 23.
They define the following zero sequence connections that are shown in Section
5.5.5, Two Winding Transformer Zero Sequence Network Diagrams and Connection
Codes.
1, 11 series path, no ground path.
2, 12 no series path, ground path on Winding 1 side.
3, 13 no series path, ground path on Winding 2 side.
4, 14 no series or ground paths.
5, 15 series path, ground path on Winding 2 side (normally only used as part of a three-
winding transformer).
6, 16 no series path, ground path on Winding 1 side, earthing transformer on Winding
2 side.
7, 17 no series path, earthing transformer on Winding 1 side, ground path on Winding
2 side.
8, 18 series path, ground path on each side.
9, 19 series path on each side, ground path at the junction point of the two series
paths.
20 series path on each side, ground path at the junction point of the two series
paths; wye grounded - wye grounded core type transfromer
21 series path, no ground path; wye grounded - wye grounded non core type auto
transfromer
22 series path, no ground path; wye - wye ungrounded core type auto transfromer
For a three-winding transformer, CC may be specified as a three digit number, each
digit of which is 1 through 7; the first digit applies to Winding 1, the second to
Winding 2, and the third to Winding 3, where the winding connections correspond to
the first seven two-winding transformer connections defined above and shown in
Section 5.5.6, Three Winding Transformer Zero Sequence Network Diagrams and
Connection Codes.
Alternatively, several common zero sequence three-winding transformer connection
combinations may be specified using the single digit values 1 through 6. These
define the zero sequence transformer connections that are shown in Figure 2-4.
The following single digit three-winding connection codes are available, where the
connection codes of the three two-winding transformers comprising the three-
winding transformer are shown in parenthesis in winding number order:
1, 11 series path in all three windings, Winding 1 ground path at the star point bus (5-1-
1).
2, 12 series path in Windings 1 and 2, Winding 3 ground path at the star point bus (1-1-
3).
3, 13 series path in Winding 2, ground paths from windings one and three at the star
point bus (3-1-3).

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4, 14 no series paths, ground paths from all three windings at the star point bus (3-3-3).
5, 15 series path in windings one and three, ground path at the Winding 2 side bus (1-
2-1).
6, 16 series path in all three windings, no ground path (1-1-1).
17 series path in Windings 1 and 2, Winding 3 ground path at the star point bus; wye
grounded - wye grounded - delta auto transfromer
18 series path in Windings 1 and 2, no ground path in Winding 3;wye - wye - delta
ungrounded neutral auto transfromer
Section 5.5.3, Transformers in the Zero Sequence, includes examples of the proper
specification of CC and the remaining transformer data items for several types of
transformers.
CC = 14 by default.
RG1, XG1 Zero sequence grounding impedance on winding 1 for an impedance grounded
transformer.
This data is specified in units specified by CZG.
Refer zero sequence network diagram for each connection code for specifying this
value.
RG1 = 0.0 and XG1 = 0.0 by default.
R01, X01 Refer zero sequence network diagram for each connection code for specifying this
value. This value could be:
• Two winding transformer: Z01 is equal to the transformer's zero sequence leakage
impedance. Z01 is equal to the transformer's positive sequence impedance by default.
• Three winding transformers and connection codes CC=11 and higher: Z01 is equal to
the transformer's winding 1 to winding 2 zero sequence impedance. Z01 is equal to the
transformer's winding 1 to winding 2 positive sequence impedance by default.
• For three winding transformers and connection codes CC=1 through 9: Z01 is equal to
the transformer's winding 1 star-circuit equivalent zero sequence impedance. is equal
to the transformer's winding 1 star-circuit equivalent positive sequence impedance by
default.
This data is specified in units specified by CZ0.
RG2, XG2 Zero sequence grounding impedance on winding 2 for an impedance grounded
transformer. This data is applicable for connection codes CC=11 and higher.
This data is specified in units specified by CZG.
Refer zero sequence network diagram for each connection code for specifying this
value. RG2 = 0.0 and XG2 = 0.0 by default.

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Program Operation Manual Zero Sequence Transformer Data

R02, X02 Refer zero sequence network diagram for each connection code for specifying this
value. This value could be:
• For two winding transformer:
Refer zero sequence network diagram for each connection code for specifying Z02
value. R02 = 0.0 and X02 = 0.0 by default.
• For three winding transformer and connection codes CC=11 and higher:
Z02 is equal to the transformer's winding 2 to winding 3 zero sequence impedance.
Z02 is equal to the transformer's winding 2 to winding 3 positive sequence impedance by
default.
• For three winding transformer and connection codes CC=1 through 9: Z02 is equal
to the transformer's winding 2 star-circuit equivalent zero sequence impedance. Z02 is
equal to the transformer's winding 2 star-circuit equivalent positive sequence
impedance by default.
This data is specified in units specified by CZ0.
RG3, XG3 Zero sequence grounding impedance on winding 3 for an impedance grounded
transformer. This data is applicable for connection codes CC=11 and higher. This
data is specified in units specified by CZG.
Refer zero sequence network diagram for each connection code for specifying this
value. RG3 = 0.0 and XG3 = 0.0 by default.
R03, X03 Refer zero sequence network diagram for each connection code for specifying this
value. This value could be:
• For three winding transformer and connection codes CC=11 and higher: Z03 is
equal to the transformer's winding 3 to winding 1 zero sequence impedance.
Z03 is equal to the transformer's winding 3 to winding 1 positive sequence impedance by
default.
• For three winding transformer and connection codes CC=1 through 9: Z03 is equal
to the transformer's winding 3 star-circuit equivalent zero sequence impedance.
Z03 is equal to the transformer's winding 3 star-circuit equivalent positive sequence
impedance by default. This data is specified in units specified by CZ0.
R N U T R L , Zero sequence common neutral grounding impedance. This data is applicable for
XNUTRL connection codes CC=11 and higher.
This data is specified in units specified by CZG.
Refer zero sequence network diagram for each connection code for specifying this
value.
RNUTRL = 0.0 and XNUTRL = 0.0 by default.

Refer Sections 5.5.4, 5.5.5 and 5.5.6 for transformer winding connections, zero sequence network
diagrams and connection codes.

In specifying zero sequence impedances for three-winding transformers, note that winding imped-
ances are required, and that the zero sequence impedances return to the default value of the
positive sequence winding impedances. Recall that, in specifying positive sequence data for three-
winding transformers (refer to Transformer Data), measured impedances between pairs of buses
to which the transformer is connected, not winding impedances, are required. PSS®E converts the
measured bus-to-bus impedances to winding impedances that are subsequently used in building
the network matrices. Activities LIST and EXAM tabulate both sets of positive sequence
impedances.

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Recall that the service status of a three-winding transformer may be specified such that two of its
windings are in-service and the remaining winding is out-of-service (refer to Transformer Data).
Recall also that data for the three windings of a three-winding transformer is stored in the working
case as three two-winding transformers (refer to Three-Winding Transformer Notes). Ri + jXi is
stored with the two-winding transformer containing winding i’s data; RG + jXG is stored with the two-
winding transformer containing the data of the winding at which it is applied.

Placing one winding of a three-winding transformer out-of-service may require a change to the zero
sequence data of the two windings that remain in-service. As the fault analysis calculation functions
construct the zero sequence admittance matrix, when a three-winding transformer with one winding
out-of-service is encountered, all data pertaining to the out-of-service winding (i.e., pertaining to the
two-winding transformer containing the data of the out-of-service winding) is ignored. Thus, any
zero sequence series and ground paths resulting from the impedances and connection code of the
out-of-service winding are excluded from the zero sequence admittance matrix. It is the user’s
responsibility to ensure that the zero sequence impedances and connection codes of the two in-
service windings result in the appropriate zero sequence modeling of the transformer.

Specification of the transformer connection code along with the impedances entered here enables
the fault analysis activities to correctly model the zero sequence transformer connections, including
the ground ties and open series branch created by certain grounded transformer windings. If no
connection code is entered for a transformer, all windings are assumed to be open. Section 5.5.3,
Transformers in the Zero Sequence gives additional details on the treatment of transformers in the
zero sequence network, including examples of specifying data for several types of transformers.

During the initial input of sequence data (i.e., IC = 0 on the first data record), any transformer for
which no data record of this category is entered has it zero sequence winding impedance(s) set to
the same value(s) as its positive sequence winding impedance(s). In subsequent executions of
activity RESQ (i.e., IC = 1 on the first data record), any transformer for which no data record of this
category is entered has its zero sequence transformer data unchanged.

Zero sequence transformer data input is terminated with a record specifying a from bus number of
zero.

Figure 2-3. Two-Winding Transformer Positive Sequence Connections

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Program Operation Manual Zero Sequence Switched Shunt Data

Positive Sequence

Winding 1 Winding 2

t1  1:1 1:t2  2

Z1+ Z2+

Z3+

1:t3 3

Winding 3

Figure 2-4. Three-Winding Transformer Positive Sequence Connections

2.9 Zero Sequence Switched Shunt Data

Zero sequence shunt admittances for switched shunts are entered into the working case in zero
sequence switched shunt data records in the Sequence Data File. Each switched shunt data record
has the following format:

I, BZ1, BZ2, ... BZ8

where:

I Bus number; bus I must be present in the working case with positive sequence
switched shunt data.
BZi Zero sequence reactance increment for each of the steps in block i; entered in
MVAR at 1 pu unit voltage. BZi = 0.0 by default.

Data specified on zero sequence switched shunt data records must be coordinated with the corre-
sponding positive sequence data (refer to Switched Shunt Data). The number of blocks and the
number of steps in each block are taken from the positive sequence data.

Activity RESQ generates an alarm for any block for which any of the following applies:

• The positive sequence admittance is positive and the zero sequence admittance is
negative.

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Zero Sequence Fixed Shunt Data Program Operation Manual

• The positive sequence admittance is negative and the zero sequence admittance is
positive.
• The positive sequence admittance is zero and the zero sequence admittance is non-
zero.
The zero sequence admittance switched on at a bus is determined from the bus positive sequence
value, with the same number of blocks and steps in each block switched on.

Zero sequence switched shunt data input is terminated with a record specifying a bus number of
zero.

2.10 Zero Sequence Fixed Shunt Data

Zero sequence fixed shunts are entered into the working case in zero sequence fixed shunt data
records in the Sequence Data File. Each zero sequence fixed shunt data record has the following
format:

I, ID, GSZERO, BSZERO

where:

I Bus number; bus I must be present in the working case.

ID One- or two-character shunt identifier of the fixed shunt at bus I for which the data is
specified by this record. A fixed shunt at bus I with the identifier ID must exist in the
working case (refer to Fixed Bus Shunt Data). ID = 1 by default.
GSZERO Active component of zero sequence admittance to ground to represent this fixed
shunt at bus I; entered in MW at 1 pu voltage.
BSZERO Reactive component of zero sequence admittance to ground to represent this fixed
shunt at bus I; entered in MVAR at 1 pu voltage.

For any fixed shunt for which either no such data record is specified or GSZERO and BSZERO are
both specified as 0.0, no zero sequence ground path is modeled for this fixed shunt. The zero
sequence ground tie created by a grounded transformer winding is automatically added to whatever
zero sequence fixed shunt and shunt load is specified at the bus when the transformer winding con-
nection code data for the transformer is specified (refer to Zero Sequence Transformer Data).

Zero sequence fixed shunt data input is terminated with a record specifying a bus number of zero.

2.11 Induction Machine Sequence Data

Each zero sequence induction machine data has the following format:

I, ID, CZG, GRDFLG, ILR2IR_SUB, R2X_SUB, ZR0, ZX0, ZRG, ZXG, ILR2IR_TRN,

R2X_TRN, ILR2IR_NEG, R2X_NEG

I Bus number; bus I must be present in the working case as an induction

machine bus.
ID One or two character identifier of the induction machine at bus I for which the
data is specified by this record. ID = 1 by default.

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Program Operation Manual Induction Machine Sequence Data

CZG Units of grounding impedance (ZRG and ZXG) values, = 1 for pu (on bus
voltage base and MBASE), = 2 for Ohms
GRDFLG 1 for grounded machine, 0 for ungrounded machine (Most commonly, stator
winding is either delta connected or star connected with the neutral isolated.)
GRDFLG=0 by default.
ILR2IR_SUB Ratio of positive sequence subtransient locked rotor current to rated current.
R2X_SUB Ratio of positive sequence subtransient resistance to reactance. This is used
only when positive sequence impedance is calculated using ILR2IR_SUB.
R2X_SUB=0.0 by default.
ZR0 Zero sequence resistance; entered in pu on machine base (i.e., on bus voltage
base and MBASE). ZR0 = 0.0 by default.
ZX0 Zero sequence reactance; entered in pu on machine base (i.e., on bus voltage
base and MBASE). ZX0 = ZXPPDV by default depending on generator
impedance option. Induction machine is isolated in zero sequence if the stator
winding is either delta connected or star connected with the neutral isolated. For
a star
connected stator winding with an earthed neutral, zero sequence impedance is
much smaller than motor starting impedance (subtransient or transient) and
does not vary with time. Induction machine zero sequence impedance can be
assumed equal to the stator ac resistance
ZRG Grounding resistance; entered in pu on machine base (i.e., on bus voltage base
and MBASE) when CZG=1 or in ohms when CZG=2. ZRG = 0.0 by default.
ZXG Grounding reactance; entered in pu on machine base (i.e., on bus voltage base
and MBASE) when CZG=1 or in ohms when CZG=2. ZXG = 0.0 by default.
ILR2IR_TRN Ratio of positive sequence transient locked rotor current to rated current.
R2X_TRN Ratio of positive sequence transient resistance to reactance. This is used only
when positive sequence impedance is calculated using ILR2IR_TRN.
R2X_TRN=0.0 by default.
ILR2IR_NEG Ratio of negative sequence locked rotor current to rated current.
R2X_NEG Ratio of negative sequence resistance to reactance. This is used only when
negative sequence impedance is calculated using ILR2IR_NEG. R2X_NEG=0.0
by default.

Application Notes:

Positive (ZP) and negative (ZN) sequence impedances are calculated as below.

1. When locked rotor current to rated current sequence data is provided, depending on
activity "reactance" option used:
1 1
ZP  --------------------------------------
ILR2IR–SUB or ILR2IR –TRN
---------------------------------------

1
ZN = ---------------------------------------
ILR2IR – NEG

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Non-Conventional Source Fault Contribution Data Program Operation Manual

2. When locked rotor current to rated current sequence data is not provided:

X1 X2
X m X 3 + --------------------
X1 + X2
X = X  + --------------------------------------------------
X1 X2
X m + X 3 + --------------------
X1 + X2

Rm = Ra

ZP = ZN = R m + jX

3. When ILR2IR_NEG and R2X_NEG are not provided, ZN=ZP.

+ Ra+jXa jX3 Ra+jXa jX3

Ea R1/s R2/s R1/(2-s) R2/(2-s)
jXm +jX1 +jX2 jXm +jX1 +jX2
-

ZR0+jZX0
RP+jXP RN+jXN
+
Ea 3(ZRG+jZXG)
-
Reference Reference
(a) Positive Sequence (b) Negative Sequence (c) Zero Sequence

Figure 2-5. Induction machine sequence networks

2.12 Non-Conventional Source Fault Contribution Data

The fault contribution from non-conventional sources like Type 3 and Type 4 Wind Generators and
Photo Voltaic Sources is very much dependent on the voltage source converters used, and is fun-
damentally different from conventional synchronous fault contribution. In most of the machines
cases, the converter design and control determines the fault contribution. This fault current contri-
bution is modeled as shown below.

Bus

G
Ci = CiP + j CiQ

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Program Operation Manual Non-Conventional Source Fault Contribution Data

In order to accommodate large number of possibilities and still provide flexibility, the fault contribu-
tion data is provided as a time dependent capability curve. Each data record has following format:

I, ID, T1, C1P, C1Q, T2, C2P, C2Q, T3, C3P, C3Q, T4, C4P, C4Q, T5, C5P, C5Q, T6, C6P, C6Q

Where:

I Bus number; bus I must be present in the working case as a generator bus.
No default is allowed.
ID One or two character machine identifier of the generator bus I for which the
data is specified by this record. ID=1 by default.
Ti Time in seconds
CiP The active component of the fault current contribution in pu on rated (nominal)
current and rated voltage base (1.0 pu) at time Ti
CiQ The reactive component of fault current contribution in pu on rated (nominal)
current and rated voltage base (1-0 pu) at time Ti. When supplying reactive
power, specify CiQ as positive.

Application Notes

• Generally T1 would be 0.0, and then C1P and C1Q would provide momentary fault con-
tribution from this source (activity ASCC).
• The pu positive sequence impedance on base of MBASE and bus nominal voltage cal-
culated as below is used in fault calculations as generator impedance.

1
Z 1 = ---------------------------------
 CiP – jCiQ 

The negative sequence and zero sequence impedance are assumed to same as positive sequence
impedance.

• The contribution to fault by this source is calculated as:

MBASE
I = ----------------------  CiP – jCiQ 
3V

where:

MBASE is the non-conventional source rated MVA base specified on generator data record.

V is the machine bus voltage.

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Non-Conventional Source Fault Contribution Data Program Operation Manual

Figure 2-6. Non-conventional Source Fault Current Contribution

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Optimal Power Flow Data Contents

Chapter 3 - Optimal Power Flow Data Contents

3.1 Overview
The input stream to activity ROPF is a Optimal Power Flow Data File containing 17 groups of
records with each group specifying a particular type of OPF data or constraint definition required for
OPF work (see Figure 3-1). Any piece of equipment for which OPF data is to be entered in activity
ROPF must be represented as power flow data in the working case. That is, activity ROPF will not
accept data for a bus, generator, branch, switched shunt or fixed shunt not contained in the working
case.

All data is read in free format with data items separated by a comma or one or more blanks. Each
category of data except the change code is terminated by a record specifying an I value of zero.
Termination of all data is indicated by a value of Q.

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Change Code Program Operation Manual

Change Code

Bus Voltage Constraint Data

Adjustable Bus Shunt Data

Bus Load Data

Adjustable Bus Load Table Data

Generator Dispatch Data

Active Power Dispatch Data

Generation Reserve Data

Generation Reactive Capability Data

Adjustable Branch Reactance Data

Piece-wise Linear Cost Data

Piece-wise Quadratic Cost Data

Polynomial and Exponential Cost Table

Period Reserve Constraint Data

An individual record of "0"
must follow each complete
Branch Flow Constraint Data record (each record may
contain multiple lines)
within each of these data
Interface Flow Constraint Data categories. A final record
containing a "0" must still
Linear Constraint Dependency Data be used to indicate the end
of the entire data category.

Figure 3-1. Optimal Power Flow Raw Data File Structure

3.2 Change Code

The OPF data modification code indicates whether a new set of optimal power flow data records
are to be loaded into the working case, or whether the existing optimal power flow data is to be mod-
ified or appended with updated information. This value is only used within the OPF Raw Data File.

Within the OPF Raw Data File, this record contains one data field entered as follows:

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Program Operation Manual Bus Voltage Constraint Data

ICODE
where ICODE is specified as one of two values:

0: All data within the OPF Raw Data File is treated as new data and entered into the
PSS®E working case. Any optimal power flow data that may have previously
existed within the working case is erased prior to the reading of the rest of the
data records contained within the OPF Raw Data File.
1: All data within the OPF Raw Data File is to supersede values that currently exist
in the working case. Any data records introduced through the OPF Raw Data File
which do not correspond to an existing record within the working case, are
automatically appended to the data records already within the current working
case. Data records which do correspond to an entry within the working case are
simply updated to reflect the new values.

3.3 Bus Voltage Constraint Data

OPF Bus Voltage Constraint records define lower and upper voltage limits at each bus existing
within the PSS®E power flow data model. Constraints may only be applied to existing buses; no
new buses may be added through the Bus Voltage Constraint record.

By default, all buses within the working case automatically have OPF Bus Voltage Constraint
records defined. The OPF Bus Voltage records of out of service (Type 4) buses can be modified but
the bus and all bus associated models (voltage constraints, bus shunts, loads, etc.) will not be uti-
lized by the optimal power flow solution process.

Bus Voltage Attribute Data Record

The format for each OPF Bus Voltage Attribute record is:

Bus, Vnmax, Vnmin, Vemax, Vemin, Ltyp, SLpen

When entered in the OPF Raw Data File each field must be separated by either a space or a
comma. Any blank fields must be delineated by commas. A bus value of zero (0) indicates that no
further bus voltage constraint records are to be processed.

Each bus voltage constraint record is uniquely identified by a bus identifier. The values for each
record is defined as follows:

Bus number, Bus

A number between 1 and 999997. The specified bus number must correspond to a bus
already defined within the power flow working case.
Normal maximum voltage, Vnmax [9999.0]
The maximum bus voltage magnitude value, entered in pu.
The normal and emergency OPF bus voltage limits are independent of the normal and
emergency bus voltage limits in the main network bus data. The OPF bus voltage limits
may be initialized to those of the network bus voltage limits through either the OPF bus
and bus subsystem spreadsheets, or through the OPF bus API commands.
Normal minimum voltage, Vnmin [-9999.0]

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Adjustable Bus Shunt Data Program Operation Manual

The minimum bus voltage magnitude value, entered in pu.

Emergency maximum voltage, Vemax [9999.0]
The maximum emergency bus voltage magnitude value, entered in pu.
To enforce recognition of the minimum and maximum emergency voltage limits during
the OPF solution, select the Impose emergency bus voltage limits solution option. Oth-
erwise the normal voltage limits, as entered above, will be utilized. Refer to Impose
Emergency Bus Voltage Limits for more information.
Emergency minimum voltage, Vemin [-9999.0]
The minimum emergency voltage magnitude value, entered in per unit.
Limit type, Ltyp [Hard limit (1)]
One of four limit types may be enforced during the OPF solution:
• Reporting only (0)
• Only report on violations of the bus voltage limits, taking no action if the voltage
falls outside of limits.
• Hard limit (1)
• Strictly enforce the specified bus voltage magnitude limits through the use of
barrier terms.
• Soft limit with a linear penalty (2)
• Permit bus voltages to go outside of their specified voltage magnitude limits,
but penalize excursions linearly. The Soft limit penalty weight, as defined
below, is used in conjunction with this penalty to indicate severity of excursion.
• Soft limit with a quadratic penalty (3)
• Permit bus voltages to go outside of their specified voltage limits, but penalize
excursions along a quadratic curve. The Soft limit penalty weight, as defined
below, is used in conjunction with this penalty to indicate severity of excursion.
Refer to Section 14.7.2 Accommodating Inequality Constraints for more information on
the limit type options.
Soft limit penalty weight, SLpen [1.0]
The penalty weight value applied to either the linear or quadratic soft limit penalty func-
tions. The larger the number, the higher the penalty for voltage excursions outside of
limits.

3.4 Adjustable Bus Shunt Data

Adjustable Bus Shunt Records define candidate bus locations for shunt compensation. These
records are unique to the PSS®E OPF but do impact bus shunts within the power flow data model
after an OPF solution. If a corresponding bus and bus shunt identifier is found, then the BINIT value
will be updated with the new OPF solution value; otherwise a new bus shunt will be added to the
power flow network data. The switched shunt data records defined within the PSS®E power flow
data model are not affected by the OPF Adjustable Bus Shunt data.

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Program Operation Manual Adjustable Bus Shunt Data

The maximum and minimum var limits specified in the Adjustable Bus Shunt records are used in
conjunction with the Minimize Adjustable Bus Shunts objective function. Details of the adjustable
bus shunt model can be found in Section 14.6.2 Adjustable Bus Shunt.

An individual bus may have one or more adjustable bus shunts defined, each differentiated by a
unique bus shunt identifier.

Adjustable Bus Shunt Data Record

The format for each Adjustable Bus Shunt record is:

Bus, ID, Binit, Bmax, Bmin, Bcost, Ctyp, Stat, Ctbl

When entering records in the OPF Raw Data File, each field must be separated by either a space
or a comma and any fields left blank must be delineated by commas. A bus value of zero indicates
that no further Adjustable Bus Shunt records are to be processed.

The bus number and shunt identifier uniquely identifies each Adjustable Bus Shunt record. The
values for each record are described as follows:

Bus number, Bus

A number between 1 and 999997. The specified bus number must correspond to an
existing bus within the power flow working case.
Bus shunt identifier, ID
A one or two character identifier that uniquely identifies the bus shunt at the bus. If this
field is left blank, the bus shunt identifier will default to a value of 1.
The bus number and bus shunt identifier may optionally correspond to a fixed shunt
record within the power flow network. If so, then the corresponding fixed shunt data
record will be updated after an OPF solution.
Bus shunt susceptance, Binit [0.0]
The initial additional shunt value, entered in Mvar at nominal voltage.
Maximum bus shunt susceptance, Bmax [0.0]
The maximum bus shunt limit, entered in Mvar.
To define an initial fixed shunt component, deployed at no cost, enter the desired value
into the main power flow model as a fixed bus shunt with the same bus number and
shunt identifier.
Minimum bus shunt susceptance, Bmin [0.0]
The minimum bus shunt limit, entered in Mvar.
Negative or positive shunt values may be entered for the maximum and minimum bus
shunt susceptance to indicate inductors or capacitors respectively.
Cost scale coefficient, Bcost [1.0]
The cost coefficient, entered in cost units per Mvar. This coefficient assigns a cost
value to each Mvar employed during the solution process.
For example, one application for the cost scale coefficient is to assign a relatively low
cost to an Adjustable Bus Shunt record representing an existing var installation, and a

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high cost to an Adjustable Bus Shunt record representing a potentially new installation.
This higher cost may take into consideration the additional costs associated with the
purchase of new equipment and the labor required for installation. This setup ensures
that vars from the existing installation will likely be employed during solution before any
new vars are applied.
Status, Stat [In (1)]
• In-service (1)
• Out of service (0)
The status switch determines whether the specified bus shunt control should be con-
sidered active or not. Only in-service bus shunts are recognized as candidates for var
control.
Cost curve type, Ctyp
This value is not currently utilized by the program.
Cost curve table number, Ctbl
This value is not currently utilized by the program.

3.5 Bus Load Data

Each OPF Bus Load Data record points to an Adjustable Bus Load table (Section 3.6 Adjustable
Bus Load Table Data) that, in turn, defines load limits for use in load adjustment studies (i.e., load
shedding, power transfer). These records are used in conjunction with the Minimize Adjustable Bus
Loads objective function.

By default, all bus loads within the working case are initialized with default OPF Bus Load data.
When a new bus load is added to the power flow network, a corresponding OPF Bus Load data
record will automatically be created with default values. These data values may be updated. Bus
loads connected to buses that are out of service can have their OPF Bus Load Data modified, but
the load will not be acknowledged by the optimal power flow solution process.

Bus Load Data Record

The format for each OPF Bus Load record is as follows:

Bus, LoadID, Loadtbl

Within the OPF Raw Data File each field must be separated by either a space or a comma. A bus
value of zero indicates that no further adjustable bus load records are being entered.

The bus number and load identifier uniquely identify each adjustable bus load record. The values
for the record are described as follows:

Bus number, Bus

A number between 1 and 999997. The specified number must correspond to a bus
already defined within the power flow working case.
Bus load identifier, LoadID
A one or two character load identifier that uniquely identifies the load at the bus. If left
blank, a default bus load identifier of 1 is assumed.

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Program Operation Manual Adjustable Bus Load Table Data

Adjustable bus load table, Loadtbl [0]

The adjustable bus load table reference number, as presented in Section 3.6 Adjust-
able Bus Load Table Data.
An adjustable bus load table number of zero indicates that the corresponding bus load
is not being utilized within any OPF Adjustable Bus Load models.
Multiple OPF bus load records may reference the same adjustable bus load table num-
ber.

3.6 Adjustable Bus Load Table Data

Adjustable Bus Load Table records define load scaling limits for use in load adjustment studies (load
shedding, power transfer). They are referenced by the OPF Bus Load records defined in
Section 3.5 Bus Load Data and are used in conjunction with the Minimize Adjustable Bus Loads
objective. Details of the load adjustment model are covered in Section 14.6.3 Load Adjustment.

An Adjustable Bus Load Table must be defined before it can be referenced by an OPF Bus Load
record. Not all Adjustable Bus Load Tables however have to be referenced by an adjustable bus
load record. Those tables which are defined but not referenced are ignored during the OPF solution
process. There may be up to 1000 Adjustable Bus Load Table records defined within the working
case.

Adjustable Bus Load Table Data Record

The format of each Adjustable Bus Load Table record is:

Tbl, LM, LMmax, LMmin, LR, LRmax, LRmin, LDcost, Ctyp, Stat, Ctbl
When entering data in the OPF Raw Data File each field must be separated by either a space or a
comma. Any fields left blank must be delineated with commas. A load table value of zero indicates
that no further adjustable bus load table records are to be processed.

The adjustable bus load table number uniquely identifies each adjustable bus load table record. The
values for the record are defined as follows:

Adjustable bus load table number, Tbl

An integer number. A value less than four digits in length is most suitable for reporting
purposes.
Load multiplier, LM [1.0]
The initial load adjustment variable, as indicated by i in the load adjustment model of
Section 14.6.3 Load Adjustment
Maximum load multiplier, LMmax [1.0]
The maximum load adjustment multiplier, used to establish an upper limit for the load
multiplier .
To represent a load shedding model, max should be between 0.0 and 1.0 and larger
than min. For a load addition model, max should be greater than 1.0.
Minimum load multiplier, LMmin [1.0]

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Generator Dispatch Data Program Operation Manual

The minimum load adjustment multiplier, used to establish a lower limit for the load mul-
tiplier . This value should be less than or equal to the value defined for the maximum
load multiplier.
Load ratio multiplier, LR
This value is not presently utilized by the program.
Maximum load ratio multiplier, LRmax
This value is not presently utilized by the program.
Minimum load ratio multiplier, LRmin
This value is not presently utilized by the program.
Cost scale coefficient, LDcost [1.0]
The cost, in $/pu MW, assigned to each OPF bus load participating in this adjustable
bus load group.
Cost curve type, Ctyp
This value is not presently utilized by the program.
Status, Stat [In-service (1)]
• In-service (1)
• Out-of-service (0)
The status switch determines whether the specified Adjustable Bus Load Table should
be considered active or not. Only in-service Adjustable Bus Load Tables and their
associated OPF Bus Loads will be recognized as adjustable bus load candidates.
Cost table cross-reference number, Ctbl
This value is not presently utilized by the program.

3.7 Generator Dispatch Data

Generator Dispatch Data records reference Active Power Dispatch Tables (Section 3.8 Active
Power Dispatch Data) which, in turn, reference Cost Curves (Sections 3.12 to 3.14). These relation-
ships, in conjunction with the Minimize Fuel Cost objective, introduce active power controls for
generator dispatch studies.

All or a portion of the generating unit’s capacity may be made available for dispatch. The active
power dispatch model, including the minimum and maximum active power limits, is defined within
the active power dispatch table record, described in Section 3.8 Active Power Dispatch Data.

By default, all machines within the working case that do not already have generator dispatch data
defined, are initialized with default data. When a new generator is added to the power flow network,
a corresponding OPF Generator Dispatch record is automatically created with default values.

Generator Dispatch Data Record

The format for each OPF Generator Dispatch data record is:

Bus, GenID, Disp, DspTbl

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Program Operation Manual Active Power Dispatch Data

When entering data in the OPF Raw Data File each field must be separated by either a space or a
comma. A bus value of zero indicates that no further generator dispatch records are being entered.
Any blank fields must be delineated by commas.

The bus number and machine identifier uniquely identifies each Generator Dispatch record. The
values for each Generator Dispatch data record are described as follows:

Bus number, Bus

A number between 1 and 999997. The specified bus number must correspond to a bus
already defined within the power flow working case.
Machine identifier, GenID
A one or two character identifier that uniquely identifies the machine at the bus. If left
blank, a default machine identifier of 1 is assumed.
Dispatch fraction, Disp [1.0]
The fractional value of the machine’s total active power output available for participa-
tion in the active power dispatch control.
A value of 1.0 indicates that 100% of the current active power output at the machine
will be employed in the associated active power control.The sum of the dispatch frac-
tions for all of the generator dispatch records that reference the same active power dis-
patch table should add up to 1.0 for typical applications.
Active Power Dispatch Table number, DspTbl [0]
The table number of the active power dispatch control table.
Multiple generator dispatch records may reference the same active power dispatch
table. An active power dispatch table number of zero implies that the generator is not
participating as an active power control.

3.8 Active Power Dispatch Data

Active Power Dispatch Table records define the maximum and minimum active power dispatch
limits.

Each Active Power Dispatch Table references a Cost Curve (Sections 3.12- 3.14) that specifies the
costs associated with dispatching generation between the defined active power limits. Active Power
Dispatch Table records in turn are referenced by Generator Dispatch records (Section 3.7 Gener-
ator Dispatch Data). The combination of these data records are used in conjunction with the
Minimize Fuel Cost objective to perform dispatch studies.

Active Power Dispatch Data Record

The format for each Active Power Dispatch Table data record is:

Tbl, Pmax, Pmin, Fuelcost, Ctyp, Status, Ctbl

When entering data in the OPF Raw Data File each field must be separated by either a space or a
comma. Any fields left blank must be delineated with commas. A table value of zero indicates that
no further active power dispatch table records are to be processed.

Each active power dispatch table is uniquely identified by a numerical identifier. The values of each
record are defined as follows:

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Generation Reserve Data Program Operation Manual

Active power dispatch table number, Tbl

An integer number. A number less than four digits is most suitable for reporting pur-
poses.
Maximum Active Power Generation, Pmax [9999.0]
The upper limit on the total amount of active power available for dispatch, specified in
MW.
Minimum Active Power Generation, Pmin [-9999.0]
The lower limit on the total amount of active power available for dispatch, specified in
MW.
Fuel Cost Scale Coefficient, Fuelcost [1.0]
A value chosen such that when the product between this value and the associated cost
curve coordinate value produces a result that has cost units of (cost units)/hour.
As an example, if the cost curve table coordinate value has units of MBTU/hour, then
the fuel cost scale coefficient should be entered with units of (cost units)/MBTU.
Cost Curve Type, Ctyp [Polynomial and exponential (1)]
• Polynomial and exponential curve (1)
• Piece-wise linear curve (2)
• Piece-wise quadratic curve (3)
One of three cost curve models may be specified to represent the fuel dispatch curves
of the generator units.
Status, Status [In (1)]
• In-service (1)
• Out-of-service (0)
The status switch indicates whether the active power dispatch record is an active con-
trol within the OPF problem statement or not. Only in-service active power dispatch
tables and their associated generators will be recognized as active power dispatch can-
didates.
Cost Curve Table Number, Ctbl [0]
The table number of the cost curve to employ.
Multiple active power dispatch table records may reference the same cost curve. A cost
curve table number of zero indicates that the active power dispatch record, along with
its participating generators will not be utilized within the OPF solution.

3.9 Generation Reserve Data

Generation Reserve records define a generating unit’s MW output capability and ramp rate. These
records are used in conjunction with the Period Reserve Constraint records (Section 3.15 Period
Reserve Constraint Data) to introduce MW reserve constraints into the optimal power flow problem.

Generation Reserve records may be utilized by one or more generation Period Reserve Constraint
records. The period reserve constraint model, as described in Section 14.6.6 Generator Period

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Program Operation Manual Generation Reactive Capability Data

Reserve, provides a means of imposing a specified MW reserve within a certain time limit (i.e., 200
MW in 10 minutes) by the participating generator reserve units.

Generation Reserve Data Record

The format for each Generation Reserve record is:

Bus, GenID, Ramp, RTMWmax

When entering records into the OPF Raw Data File, each field must be separated by either a space
or a comma. A bus number of zero indicates that no further generator reserve records are being
entered. Any blank fields must be delineated by commas.

The bus number and machine identifier uniquely identifies each Generation Reserve record. The
values for each record are defined as follows:

Bus number, Bus

A number between 1 and 999997. The specified bus number must correspond to a bus
defined within the power flow working case.
Machine identifier, GenID
The one or two character machine identifier corresponding to a machine in the working
case. If this field is left blank, a default machine identifier of 1 is assumed.
Unit ramp rate, Ramp [9999.0]
The rate at which it takes the generator to reach its maximum MW capability, specified
in MW/minute.
Unit capability, RTMWmax [9999.0]
The maximum unit reserve contribution, specified in MW.

3.10 Generation Reactive Capability Data

Generation Reactive Capability records define the limits in the armature reaction and stator current
magnitude.

Whereas the conventional generator model provides for constant reactive generation limits, the
reactive capability model represents generator armature reaction (Efd) behind synchronous reac-
tance (Xd). With limits applied to armature reaction magnitude and stator current magnitude, the
reactive power capability of the unit is recognized in a manner which is independent of any assump-
tions in terminal voltage magnitude or active power generation. This is further discussed in
Section 14.6.5 Generator Reactive Capability.

Generation Reactive Capability Data Record

The format for each Reactive Capability record is:

Bus, GenID, Xd, Is,max, PFlag, PFlead, Qlimit, Status

When entering records in the OPF Raw Data File each field must be separated by either a space
or a comma and any fields left blank must be delineated with commas. A bus number of zero indi-
cates that no further generator reactive capability records are being entered.

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Adjustable Branch Reactance Data Program Operation Manual

A bus number and machine identifier is used to uniquely identify each Generation Reactive Capa-
bility record. The values for each record are defined as follows:

Bus number, Bus

A number between 1 and 999997. The specified bus number must correspond to a bus
already defined within the power flow working case.
Machine identifier, GenID
The one or two character machine identifier of a valid machine within the working case.
If this field is left blank, a default machine identifier of 1 will be assumed.
Synchronous Reactance, Xd [1.0]
The direct axis synchronous reactance of the machine, entered in pu on machine base.
Stator Current Limit, Is,max [1.0]
The generator stator current limit, entered in pu on machine base.
Lagging Power Factor, PFlag [1.0]
Real value generator rated lagging power factor.
Leading Power Factor, PFlead [1.0]
Real value generator rated leading power factor.
Maximum Reactive Absorption, Qlimit [1.0]
The maximum reactive absorption limit at zero power factor, entered in pu on machine
base.
Reactive Capability Limit Status, Status [Enabled with fixed Efd (4)]
• Out-of-service (0)
The program will employ reactive generation limits directly from the power flow
data.
• Enabled (1)
The generator is fully enabled with no reactive generation limits.
• Enabled with +Efd inhibited (2)
The generator is in service and any increase in the field voltage is inhibited.
• Enabled with -Efd inhibited (3)
The generator is in service and any decrease in the field voltage is inhibited.
• Enabled with Efd fixed (4)
The generator is in service with an invariant field voltage.
The limit status determines how the specified reactive capability record should be
employed in the optimal power flow problem.

3.11 Adjustable Branch Reactance Data

Adjustable Branch Reactance records define the reactive compensation limits and associated
costs of adding series var compensation. The data records are used in conjunction with the Mini-
mize Adjustable Branch Reactances objective to identify candidate branches for use in series var

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compensation studies. A full description of the adjustable branch reactance model is presented in
Section 14.6.4 Adjustable Branch Reactance.

Adjustable Branch Reactance Data Record

The format for each Adjustable Branch Reactance record is:

IBus, JBus, CktID, Xmlt, Xmltmax, Xmltmin, Xcost, Ctyp, Status, Ctbl
Each field must be separated by either a space or a comma and any fields left blank must be delin-
eated by commas. An IBus number of zero indicates that no further adjustable branch reactance
records are being entered.

The from bus, to bus and circuit identifier uniquely identify each Adjustable Branch Reactance
record. The values for each record are defined as follows:

From bus number, IBus

The sending bus, specified by a number between 1 and 999997. The number must cor-
respond to a bus already contained within the power flow working case.
To bus number, JBus
The receiving bus, specified by a number between 1 and 999997. The number must
correspond to a bus already contained within the power flow working case.
Circuit identifier, CktID
The one or two character branch identifier of an existing branch between the from bus
and the to bus. If this field is left blank a default circuit identifier of 1 is assumed.
Reactance multiplier, Xmlt [1.0]
The multiplier applied to the current reactance of the branch to yield the initial series
compensation value. A value of 1.0 implies that the initial reactance will be the current
reactance of the branch as obtained from the working case.
Maximum reactance multiplier, Xmltmax [1.0]
The maximum multiplier value applied to the reactance of the branch. The calculated
value determines the upper limit on the amount of available branch reactance compen-
sation. It is specified as a fraction of the branch reactance. Values over 1.0 are allowed
for situations where a potential increase in reactance is desired.
Minimum reactance multiplier, Xmltmin [1.0]
The minimum multiplier value applied to the reactance of the branch. The calculated
value determines the lower limit on the amount of available branch reactance compen-
sation. It is specified as a fraction of the branch reactance.
For example, if the minimum reactance multiplier is specified as 0.3 and the maximum
reactance multiplier is specified as 1.0 then 70% of the branch reactance is available
as compensation.
The minimum value cannot be less than 0.1 to ensure that compensation does not
exceed 90% of the branch impedance.
Cost scale coefficient, Xcost [1.0]
The adjustable branch reactance cost in cost units / pu ohms.

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Cost curve type, Ctyp

This value is not presently utilized by the program.
Status, Status [In (1)]
• In-service (1)
• Out-of-service (0)
The status determines whether the specified Adjustable Branch Reactance record
should be considered active or not. Only in-service Adjustable Branch Reactance
records are recognized as candidates for series var adjustment.
Cost curve table number, Ctbl
This value is not presently utilized by the program.

3.12 Piece-wise Linear Cost Data

The Cost Curve data record provides essential information on the fuel cost characteristics of each
participating generator unit. It is used specifically in conjunction with the Minimize Fuel Cost objec-
tive and the Active Power Dispatch tables (Section 3.8 Active Power Dispatch Data) for generator
dispatch analysis.

The Piece-wise Linear cost model defines a linear relation between a cost, in cost units (i.e., dollars,
pounds, etc.), and a particular control variable value. For example, an active power dispatch model
may reference a piece-wise linear cost curve in order to obtain the relative fuel cost for dispatching
a participating generator unit at a certain active power dispatch level.

Piece-wise Linear Cost Table Data Record

The format for each Piece-wise Linear Cost Table data record is a multi-line record as follows:

LTbl, Label, Npairs

x1, y1
...
xN, yN
Each field within the data records of the OPF Raw Data File must be separated by either a space
or a comma, with blank fields being delineated by commas.

The total number of pairs entered must equal the value specified for Npairs.

An Ltbl number of zero indicates that no further piece-wise linear cost table records are to be
processed.

Each Piece-wise Linear Cost Curve Table record is uniquely identified by a linear cost table number.
The values for each record are defined as follows:

Piece-wise linear cost table number, LTbl

An integer number. A number less than four digits in length is most suitable for report-
ing purposes.
Note that the same cost table number may be used for multiple cost curve tables, pro-
vided that each table represents a different cost curve type (i.e., quadratic or polyno-
mial).

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Cost table label, Label [" "]

A descriptive label of the piece-wise linear cost table, containing at most, 12 charac-
ters. This label is strictly used for reporting purposes.
Number of cost pairs, Npairs [0]
The total number of xi, yi coordinate pairs being entered. This value is only used when
entering raw data records in the OPF Raw Data File format or when using PSS®E Auto-
mation commands.
Coordinate Pairs
The individual coordinate pairs. Each pair (x1, y1 through xN, yN) defines one segment
of the piece-wise linear cost curve.
• x1 … xN
The control variable value. In the typical situation where the cost curve is rep-
resenting fuel cost characteristics, this value would define the active power
generation, in MW.
• y1 … yN
The total cost or energy consumption. For the fuel cost model, this value would
typically be entered in cost units / hour.

Piece-wise Linear Cost Table

The Piece-wise Linear Cost Table displays all Piece-wise Linear Cost Tables in the working case.
The subsystem filter has no effect on the list displayed. If there are no Piece-wise Linear Cost
Tables in the working case, the Tables list will be blank.

3.13 Piece-wise Quadratic Cost Data

The Cost Curve data record provides essential information on the fuel cost characteristics of each
participating generator unit. It is used specifically in conjunction with the Minimize Fuel Cost objec-
tive and the Active Power Dispatch tables (Section 3.8 Active Power Dispatch Data).

The Piece-wise Quadratic Cost Curve model presents the cost, in cost units (i.e., dollars, pounds,
etc.), as a quadratic function of a control variable value. For example, an active power dispatch
model may reference a piece-wise quadratic cost curve to obtain the relative fuel costs for dis-
patching a participating generator unit at a certain active power dispatch level.

Piece-wise Quadratic Cost Data Record

The format for each Piece-wise Quadratic Cost Table data record is a multi-line record as follows:

QTbl, Label, Cost, Npairs

x1, y1
...
xN, yN
Each field of the data record must be separated by either a space or a comma, with any blank fields
being delineated by commas.

The total number of pairs entered must equal the value specified for Npairs.

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A Qtbl number of zero indicates that no further Piece-wise Quadratic Cost Table records are to be
entered.

Each Piece-wise Quadratic Cost Curve Table is uniquely identified by a quadratic cost table
number. The data values for each record are defined as follows:

Piece-wise quadratic cost table number, QTbl

An integer number. A number less than four digits in length is recommended for report-
ing purposes.
The same cost table number may be used for multiple cost curve table types provided
that each table of the same number represents a different cost curve type (i.e., linear
or polynomial).
Cost table label, Label [""]
A descriptive label of no more than 12 characters used to describe the piece-wise qua-
dratic cost table. This label is used for reporting purposes only.
Integration constant, Cost [0.0]
The cost or energy integration constant used to calculate the total fuel cost.
When this value is used in conjunction with the active power dispatch table, it should
be defined in units which, when its product is taken with the fuel cost scale coefficient
defined in the active power dispatch table record, the resultant units are cost units /
hour. For example, if the fuel cost scale coefficient in the active power dispatch table
has units of $/MBTU, then the integration constant should be specified in units of
MBTU/hour.
Number of cost pairs, Npairs [0]
The total number of xi, yi coordinate pairs being entered for this curve. This value is
only used when entering raw data records through either the OPF Raw Data File or
when using PSS®E Automation commands.
Coordinate Pairs
The individual coordinate pairs. Each pair (x1, y1 through xN, yN) represents one seg-
ment of the piece-wise quadratic cost curve.
• x1 … xN
The control variable value. In the typical situation where the cost curve is rep-
resenting fuel cost characteristics, this value would represent the active power
generation, in MW.
• y1 … yN
The incremental cost or energy consumption. For the fuel cost model, this
value would typically be entered in cost units/MW.

Piece-wise Quadratic Cost Table

The Piece-wise Quadratic Cost Table editor displays in the editor all Piece-wise Quadratic Cost
Curve Tables in the working case. The subsystem filter has no effect on the list displayed. If no
Piece-wise Quadratic Cost Curve Tables exist in the working case, the editor will be blank.

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3.14 Polynomial and Exponential Cost Table

The Cost Curve data records provide essential information on the fuel cost characteristics of each
participating generator unit. It is used specifically in conjunction with the Minimize Fuel Cost objec-
tive and the Active Power Dispatch tables (Section 3.8 Active Power Dispatch Data) for generator
dispatch analysis.

The Polynomial and Exponential Cost Curve model describes the cost, in cost units (i.e., dollars,
pounds, etc.), as a polynomial equation in terms of a control variable value. Similar to the linear and
quadratic cost curve models, an active power dispatch model may reference a polynomial cost
curve in order to obtain the relative fuel cost to dispatch a participating generator unit at a certain
active power dispatch level. The following equation is employed:

Cost = ( Cost0 + A • Pgen + B • P2gen + C • DPgen ) VAL

where:
Cost0 = Fuel cost integration constant
A = Linear cost coefficient
B = Quadratic cost coefficient
C = Exponential cost coefficient
D = Exponent scale factor
VAL = The cost scale coefficient. In the example of the
active power dispatch model, this value is the
fuel cost scale coefficient.

Figure 3-2. Polynomial Cost Equation

Polynomial and Exponential Cost Curve Data Record

The format for each Polynomial and Exponential Cost Curve Table record is:

Ptbl, Label, Cost, Costlin, Costquad, Costexp, Expn

Each field of the data record must be separated by either a space or a comma with blank fields delin-
eated by commas. A Ptbl number of zero indicates that no further polynomial and exponential cost
table records are being entered.

Each Polynomial and Exponential Cost Curve Table record is uniquely identified by a polynomial
and exponential cost table number. The values for each record are defined as follows:

Polynomial and Exponential cost table number, Ptbl

A numerical identifier. A number less than four digits in length is recommended for
reporting purposes.
The same table number may be used for multiple cost curve tables, provided that each
table represents a different cost curve type (i.e., linear or quadratic).
Cost table label, Label [""]

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A string containing a maximum of 12 characters. This may be used as a descriptive

label for the polynomial and exponential cost table. This value is used for reporting pur-
poses only.
Integration constant, Cost [0.0]
The cost or energy integration constant used to calculate the total fuel cost.
Linear coefficient, Costlin [0.0]
The linear cost coefficient as indicated by A in the equation given in Figure 3-2.
Quadratic coefficient, Costquad [0.0]
The quadratic cost coefficient as indicated by B in the equation given in Figure 3-2.
Exponential coefficient, Costexp [0.0]
The exponential cost coefficient as indicated by C in the equation given in Figure 3-2.
Exponent scale factor, Expn [0.0]
The scale factor value which may be applied to the exponent of the exponential term
as indicated by D in the equation given in Figure 3-2.
The values for the integration constant and each of the coefficients should be specified in units that
will allow them to be multiplied by a cost scale value. When the polynomial and exponential table is
used in conjunction with the active power dispatch table, the coefficients and integration constant
should be defined in units which, when a product is taken with the fuel cost scale coefficient defined
in the active power dispatch table record, the resulting value is in units of cost units / hour. For
example, if the fuel cost scale coefficient in the active power dispatch table has units of $/MBTU,
then the integration constant should be specified in units of MBTU/hour.

Polynomial and Exponential Cost Table

The Polynomial and Exponential Cost Table displays in the editor all Polynomial and Exponential
Cost Curve Tables that exist in the working case. The subsystem filter has no effect on the list dis-
played. If no Polynomial and Exponential Cost Curve Tables exist in the working case, the editor
will simply show a blank record.

3.15 Period Reserve Constraint Data

Period Reserve Constraint data records are used in conjunction with the Generation Reserve
records (Section 3.9 Generation Reserve Data) to impose MW reserve limits.

The period reserve constraint model, as described in Section 14.6.6 Generator Period Reserve,
defines a MW reserve that must be met within a stated time limit (i.e., 200 MW in 10 minutes). Some
or all of a group of participating generator units may be deployed to meet this requirement.The max-
imum reserve contribution in MW and the unit ramp rate in MW/minute are defined for each
participating generator unit as part of the generation reserve data presented in Section 3.9 Gener-
ation Reserve Data. The period reserve records described here define the desired reserve limit and
the time limit in which the reserve limit must be met.

Period Reserve Data Input Values

The format for each Period Reserve data record is a multi-line record as follows:

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RsvID, MWlimit, T, Status

Bus, GenID
...
Bus, GenID
0
When entering data records within the OPF Raw Data File, each field must be separated by either
a space or a comma and any fields left blank must be delineated by commas. For each complete
period reserve record entered, a single zero must be placed on the line immediately following the
last generator unit entered, or immediately after the main RsvID record if no participating units are
specified. A RsvID value of zero indicates that no further period reserve records are being entered.

Each Period Reserve record is uniquely identified by a reserve identification number between one
and fifteen. The values for each record are defined as follows:

Reserve identifier (1 - 15), RsvID

A number between one and fifteen, inclusive.
Reserve limit, MWlimit [0.0]
The reserve requirement, in MW.
If the sum of maximum reserves for all of the units participating in the Period Reserve
data record is less than the specified reserve limit, then the constraint cannot be satis-
fied. The solution will terminate if this situation arises.
If the reserve limit is set to 0.0, the reserve constraint will not be employed as part of
the optimal power flow problem statement.
Time limit, T [9999.0]
The time constraint for which the reserve requirement must be fulfilled, in minutes.
Status, Status [In (1)]
• In-service (1)
• Out-of-service (0)
The status switch indicates whether the specified period reserve record should be
included within the OPF problem statement. Only in-service period reserve records will
be included as a reserve constraint.
Participating Units
A list of participating generator reserve units available to the period reserve constraint.
Each unit must already have a corresponding generator reserve data record defined.
Each participating unit is uniquely specified by the following identifiers:
• Bus, Bus
The bus number of the bus where the unit is located. When using the spread-
sheet, this value may need to be entered as a bus name, depending upon the
input mode currently in effect.
• Unit ID, GenID
The generator unit identifier of the participating generator. A default identifier
of 1 is assumed if left blank.

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Period Reserve Data Editor

The Period Reserve data editor displays all Period Reserve data records within the working case.
The subsystem filter has no effect on the list displayed. If no Period Reserve records exist in the
working case, the editor will be blank.

3.16 Branch Flow Constraint Data

Branch Flow Constraint records define upper and lower flow limits on selected non zero impedance
branches. Four different flow limits may be imposed: MW, MVar, MVA and Ampere. More than one
branch flow constraint type may be defined for the same branch.

Branch Flow Constraint Data Record

The format of each Branch Flow Constraint record is:

IBus, JBus, CktID, BfID, Fmax, Fmin, EFmax, EFmin, Ftyp, Ltyp, Lpen,
KBus
When entering records in the OPF Raw Data File, each field must be separated by either a space
or a comma and any fields left blank must be delineated by commas. An IBus number of zero indi-
cates that no further branch flow constraint records are being entered.

The from bus, to bus, third bus (for three-winding transformers), circuit id and flow id uniquely iden-
tify each Branch Flow Constraint record. The values for each record are defined as follows:

From bus number, IBus

The sending bus, specified by a number from 1 through 999997. The number must cor-
respond to an existing bus within the power flow working case.
If a three-winding transformer is being specified, the from bus defines the winding for
which the flow constraint is being introduced.
To bus number, JBus
The receiving bus, specified by a number from 1 through 999997. The number must
correspond to an existing bus within the power flow working case.
Third bus number, KBus (very last field in the above record)
The third bus of a three-winding transformer, specified by a number from 1 through
999997. The number must correspond to an existing bus within the power flow working
case.
If a three-winding transformer is not being entered, this value is zero.
Circuit identifier, CktID
A one or two character identifier used to differentiate between multiple connecting lines
between the from bus, to bus and third bus (if three-winding transformer). If this field is
left blank, a circuit identifier of 1 is assumed.
Flow identifier, BfID
A single character identifier to differentiate between multiple branch flow constraints
defined at the same branch. If this field is left blank, a flow identifier of 1 is assumed.
Maximum normal flow limit, Fmax [0.0]

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The maximum normal flow limit on the specified branch. Values are specified in phys-
ical units appropriate to the flow limit type being specified; Ampere constraints are
specified in MVA.
If the difference between the specified upper and lower branch flow limits is less than
0.0001 then the specified flow constraint is fixed at the indicated limit.
This value, along with the minimum normal limit defined below, is used to define one of
two possible flow limits assigned to the branch. An alternate set of emergency limits is
defined below. By default, the normal flow limits are employed during the OPF solution
unless the Impose Emergency Branch Flow Limits solution option is selected.
Minimum normal flow limit, Fmin [0.0]
The minimum normal flow limit on the specified branch. Values are specified in physical
units appropriate to the flow limit type being specified; Ampere constraints are specified
in MVA.
If the difference between the specified upper and lower branch flow limits is less than
0.0001 then specified flow constraint is treated as fixed at the indicated limit.
Maximum emergency flow limit, EFmax [0.0]
The maximum emergency flow limit on the specified branch. This limit, in conjunction
with the minimum emergency limit, defines an optional alternate set of flow limits. Val-
ues are specified in physical units appropriate to the flow limit type being specified;
Ampere constraints are specified in MVA.
To enforce recognition of the minimum and maximum emergency flow limits as
opposed to the normal flow limits during the OPF solution, select the Impose Emer-
gency Branch Flow Limits solution option.
Minimum emergency flow limit, EFmin [0.0]
The minimum emergency flow limit on the specified branch. This limit, in conjunction
with the maximum emergency limit, defines an optional alternate set of flow limits. Val-
ues are specified in physical units appropriate to the flow limit type being specified;
Ampere constraints are specified in MVA.
If emergency limits are employed during the OPF solution and the difference between
the specified upper and lower emergency branch flow limits is less than 0.0001, then
the specified flow constraint is treated as fixed at the indicated limit.
Flow type, Ftyp [Ampere (4)]
One of four different flow types specified for the constraint:
• MW (1)
• MVar (2)
• MVA (3)
• Ampere (4)
Limit type, Ltyp [Hard limit (1)]
One of four constraint limit types enforced during the OPF solution:

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• Reporting only (0)

Only report on violations of the specified branch flow limits, taking no action if
the branch flow falls outside of limits.
• Hard limit (1)
Strictly enforce the specified branch flow limits through the use of barrier terms.
• Soft limit with a linear penalty (2)
Permit branch flows to go outside of their specified branch flow limits, but
penalize excursions along a linear curve. The Soft limit penalty weight, as
defined below, is used in conjunction with this penalty to indicate severity of
excursion.
• Soft limit with a quadratic penalty (3)
Permit branch flow limit to go outside of their specified flow limits, but penalize
excursions along a quadratic curve. The Soft limit penalty weight, as defined
below, is used in conjunction with this penalty to indicate severity of excursion.
Refer to Section 14.7.2 Accommodating Inequality Constraints for more information on
the limit type options.
Soft limit penalty weight, Lpen [1.0]
The penalty weight value applied to either the linear or quadratic soft limit penalty func-
tions. The larger the number, the higher the penalty for branch flow excursions outside
of limits.

3.17 Interface Flow Constraint Data

Interface flow records introduce MW or MVar flow constraints across a defined interface. These
limits are only enforced when the Constrain Interface Flows option is enabled, otherwise they are
ignored during the OPF solution. In conjunction with both the interface flow constraint records and
the directive to Constrain Interface Flows, the Minimize Interface Flows objective may be employed
to either minimize or maximize flows across an interface.

An interface consists of a collection of branches that may include the tie lines between two areas,
the flows through a particular transmission corridor, or the collection of lines emanating from an
area. Each interface flow constraint record defines a set of branches included in the interface and
the flow limits that are to be imposed on that set during the optimization process. By default, the
interface flow definitions are for informational purposes only. They do not automatically introduce
constraint equations or objective terms in the optimization problem unless one or both of the corre-
sponding Constrain Interface Flows or Minimize Interface Flows options are enforced.

Interface Flow Data Input Values

The format for each Interface Flow Constraint data record is a multi-line record as follows:

IflwID, Label, Fmax, Fmin, Ftyp, Ltyp, Lpen

Ibus, Jbus, CktID, Kbus
Ibus, Jbus, CktID, Kbus
...
0
Each field of the data record must be separated by either a space or a comma, with any blank fields
delineated by commas. For each interface flow record entered, a single zero must be placed on the

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line immediately following the last participating branch entered, or immediately after the main IflwID
record if no participating branches are specified.

An IflwID value of zero indicates that no further interface flow records are to be processed.

Each Interface Flow Constraint record is uniquely identified by an interface flow identifier. The
values for each record are defined as follows:

Interface flow identifier, IflwID

An integer number. A value less than four digits in length is most suitable for reporting
purposes.
Interface flow label, Label [""]
A string containing a maximum of 32 characters used to describe the interface. This
label is only used for reporting purposes.
Maximum interface flow limit, Fmax [0.0]
The maximum flow limit across the interface, specified in the physical units appropriate
for the specified flow limit type defined below.
If the range between the maximum and minimum interface MW flow limits is less than
0.001, then the maximum interface flow limit is set to the average of the two interface
flow limit values plus 0.1.
Minimum interface flow limit, Fmin [0.0]
The minimum flow limit across the interface, specified in the physical units appropriate
for the specified flow limit type defined below.
If the range between the maximum and minimum interface MW flow limits is less than
0.001, then the minimum interface flow limit is set to the average of the two interface
flow limit values minus 0.1.
Flow type, Ftyp [MW (1)]
One of two valid flow types:
• MW (1)
• MVar (2)
Limit type, Ltyp [Hard limit (1)]
One of four different limit types:
• Reporting only (0)
Only report on violations of the specified interface flow limits, taking no action
if the interface flow falls outside of limits.
• Hard limit (1)
Strictly enforce the specified interface flow limits through the use of barrier
terms.
• Soft limit with a linear penalty (2)
Permit interface flows to go outside of the specified interface flow limits, but
penalize excursions along a linear curve. The Soft limit penalty weight, as

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defined below, is used in conjunction with this penalty to indicate severity of

excursion.
• Soft limit with a quadratic penalty (3)
Permit interface flows to go outside of the specified interface flow limits, but
penalize excursions along a quadratic curve. The Soft limit penalty weight, as
defined below, is used in conjunction with this penalty to indicate severity of
excursion.
Refer to Section 14.7.2 Accommodating Inequality Constraints for more information on
the limit type options.
Soft limit penalty weight, Lpen [1.0]
The penalty weight value applied to either the linear or quadratic soft limit penalty func-
tions. The larger the number, the higher the penalty for interface flow excursions out-
side of the defined interface flow limits.
Participating Branches
A list of branches defining the interface. Each branch is individually specified by the fol-
lowing identifiers:
• From bus number, Ibus
The sending bus number (1 through 999997). When using the spreadsheet,
this value may optionally be entered as a bus name, provided that names input
mode is in effect.
• To bus number, Jbus
The receiving end bus number (1 through 999997). When using the spread-
sheet, this value may optionally be entered as a bus name, provided that
names input mode is in effect.
• Circuit ID, CktID
The one or two character circuit identifier. If no circuit identifier is entered, a
default value of 1 is assumed.
• Third bus number, Kbus
The third bus number (1 through 999997) if a three winding transformer is
specified; zero (0) otherwise. When using the spreadsheet, this value may
optionally be entered as a bus name, provided that names input mode is in
effect.

Interface Flow Constraint Data Table

The Interface Flow Constraint editor displays all Interface Flow Constraint records within the
working case in the data table. The subsystem filter has no effect on the list displayed. If there are
no Interface Flow Constraint records in the working case, then the editor window will be blank.

3.18 Linear Constraint Dependency Data

Linear Constraint Dependency records provide a way to introduce customized linear constraint
equations into the optimal power flow problem statement. Each dependency equation may be com-
prised of any number of variables, selected from a group of previously defined records. Details of
the linear constraint dependency equation model are discussed in Section 14.6.8 Linear Constraint
Dependency Equation.

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Linear Constraint Dependency Data Record

The format of each Linear Constraint Dependency data record is a multi-lined record as follows:

EqID, Label, Slkmax, Slkmin

Vtyp, "ID fields", Coeff
Vtyp, "ID fields", Coeff
...
0
Each field of the data record must be separated by either a space or a comma, with any blank fields
delineated by commas. For each Linear Constraint Equation record entered, a single zero must be
placed on the line immediately following the last participating variable record entered, or immedi-
ately after the main EqID record if no participating variables are specified.

An EqID value of zero indicates that no further linear constraint dependency records are to be
processed.

Each Linear Constraint Dependency record is uniquely identified by a constraint equation identifier.
The values for each field within the record are defined as follows:

Linear constraint equation identifier, EqID

An integer number. A value less than four digits in length is most suitable for reporting
purposes.
Constraint equation label, Label [""]
A string containing a maximum of 12 characters used to describe the linear constraint
dependency equation being defined. This label is used for reporting purposes only.
Maximum constraint slack, Slkmax [0.0]
The constraint equation maximum slack variable limit.
Minimum constraint slack, Slkmin [0.0]
The constraint equation minimum slack variable limit.
Participating Variables
Any number of participating variables may be included in the linear constraint depen-
dency equation. The variable identifiers must correspond to a record that already exists
within the working case.
• Dependency variable type code, Vtyp [0]

A number (1 through 10) corresponding to the type of dependency variable being

added to the constraint equation. The numerical values associated with each vari-
able type are as follows:

1. voltage magnitude, in pu

2. voltage angle, in radians (degrees/57.29578)

3. active power generation, in per unit of reactive power based on system

base(i.e. 400 MW limit base on a system base of 100 is entered as 4.0)

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4. reactive power generation, in per unit of reactive power based on system

base(i.e. 400 Mvar limit base on a system base of 100 is entered as 4.0)

5. transformer tap ratio, entered as the inverse of the tap ratio; or transformer
phase shift angle, in radians

6. branch flow, in per unit flow value based on system base

7. interface flow, in per unit flow value based on system base

8. adjustable bus shunt, in per unit Mvar value based on system base

9. switched shunt, in per unit Mvar value based on system base

10. load adjustment, entered in terms of the load multiplier (i.e. 0.8 for 80% of
load or 1.8 for 180% of load

• Variable identification fields, "ID fields"

Depending upon the variable type code selected above, one or more identification
fields must be specified in order to uniquely identify the record to be employed as
the variable entry. The identification fields corresponding to each of the variable
type codes defined above, are as follows:

1: Bus number (1 through 999997)

2: Bus number (1 through 999997)

3: Active power dispatch table number

4: Bus number (1 through 999997)

Generator identifier [" 1"]

5: From bus number

To bus number
Circuit identifier [" 1"]
Third bus number, if a three-winding transformer is specified; 
placed after the Coeff value [0]

6: From bus number

To bus number
Circuit identifier [" 1"]
Branch flow identifier ["1"]
Third bus number, if a three-winding transformer is specified; 
placed after the Coeff value [0]

7: Interface flow identifier

8: Bus number (1 through 999997)

Adjustable bus shunt identifier [" 1"]

9: Bus number (1 through 999997)

10: Adjustable bus load table number

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When using the linear constraint equation table editor, bus identifiers may alter-
nately be entered as extended bus names instead of bus number, provided that the
names input mode option is in effect.

Variable coefficient, Coeff [1.0]

A real variable coefficient applied to the dependency variable specified above.

Linear Constraint Dependency Equation Data Table

The Linear Constraint Dependency Equation data table displays in the editor all Linear Constraint
Dependency Equation records within the working case. The subsystem filter has no effect on the
list displayed. If there are no Linear Constraint Dependency Equation records in the working case,
the editor window will be blank.

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