TRANSMISSION PLANNING
Revision
Number
12
VEC-008 Electric Generation and Transmission Planning Criteria
This document is compliant with NERC Transmission Planning Standards
Transmission Planning (TPL)
VEC-008 Control Document
Electric Generation and Transmission Planning Criteria
Please refer questions about this document to the Electric Reliability Compliance
Department (812-491-4012 or 812-491-5878).
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VEC-008 Electric Generation and Transmission Planning Criteria
This document is compliant with NERC Transmission Planning Standards
TABLE OF CONTENTS
1
Introduction ..................................................................................................... 6
1.1
1.2
2
Purpose ................................................................................................................. 6
Roles and Responsibilities ................................................................................... 6
Electric Generation and Transmission Planning Procedure ...................... 7
2.1
Model Usage ........................................................................................................ 7
2.1.1 Transmission Performance Planning Models (up to 10 years) ...................... 7
2.1.2 AFC Planning models (0-3 years) .................................................................. 7
2.1.3 Operational models (current and next season) ............................................... 8
2.2
Model Development ............................................................................................. 8
2.3
Model Evaluation Criteria .................................................................................. 10
2.3.1 Contingencies ............................................................................................... 10
2.3.2 Performance ................................................................................................. 12
2.3.3 SOL and IROL Determination ..................................................................... 13
2.4
Study Results...................................................................................................... 14
3
Cross References ........................................................................................... 16
4
Appendices ..................................................................................................... 17
4.1
Appendix A: Table 1 – Steady State & Stability Performance Planning Events17
4.2
Appedix B: Table 1 – Steady State & Stability Performance Extreme Events . 20
4.3
Appendix C: Table 1 – Steady State & Stability Performance Footnotes (Planning
Events and Extreme Events) ......................................................................................... 21
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VEC-008 Electric Generation and Transmission Planning Criteria
This document is compliant with NERC Transmission Planning Standards
Revision Table
Revision
Number
0
Revision
Date
07/23/08
Effective
Date
07/28/08
Revised By
Summary of Changes
Name
R. Tabor
1
04/09/09
04/10/09
R. Tabor
2
01/12/10
01/26/10
R. Tabor
3
03/10/10
04/05/10
M. Rose
4
10/05/10
11/23/10
M. Rose
5
10/27/11
11/15/11
R. Collins
6
03/01/12
04/10/12
R. Collins
7
05/13/13
05/23/13
K. Sims
8
08/31/13
08/31/13
9
10/22/13
11/01/13
J.
Biggerstaff
J.
Biggerstaff
Revised document into new format,
added sections to address NERC FAC
and TPL standards
 Updated Annual Review Table
 Standardized document formatting.
 Added 3H Reference to VEC-014
and ratings.
 Added 4.3 SOL & IROL
Determination
 Updated reference tables to latest
reports
 Added verbiage to cover TPL-001
& TPL-002 for Transmission
Performance Planning Models (up
to 10 years) under 2 Model Usage,
2.1.
 Added Section F under Study
Results
• Made content changes based on
self-certification. See redline(s).
• Made content changes based on
annual or self-certification review.
See redline(s) and summary of
document changes.
• Made content changes based on
annual or self-certification review.
See redline(s) and summary of
document changes.
• Made content changes based on
annual or self-certification review.
See redline(s) and summary of
document changes.
• Revised MISO document link
under section 2.1.2
• Revised first paragraph of section
2.3.1. Contingencies based on
Director Review.
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VEC-008 Electric Generation and Transmission Planning Criteria
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Revision
Number
10
Revision
Date
03/24/14
Effective
Date
04/07/14
Revised By
Summary of Changes
K. Barr
•
11
07/07//14
12/10/14
K. Barr
•
12
11/06/15
12/18/15
K. Barr
•
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Made content changes based on
annual or self-certification review.
See redline(s) and summary of
document changes.
Inserted references based on
annual or self-certification review.
See redline(s) and summary of
document changes.
Made content changes based on
annual or self-certification review.
See redline(s) and summary of
document changes.
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1 Introduction
1.1 Purpose
The major functions of and guidelines for Vectren electric transmission system
planning are as follows:
a. Developing a transmission system capable of delivering voltage of constant
magnitude, duration and frequency at levels which meet our customers’ needs
during normal conditions and during a system contingency or set of contingencies,
and having established normal (pre-contingency) operating procedures in place;
b. Optimizing the system configuration such that costs (capital and operating) are
minimized while obtaining the above major function and providing a plan for
system upgrades to meet performance requirements;
c. Determining the near and long term Available Flowgate Capacity (AFC) of
Vectren electric transmission facilities for imports, exports, and flow-through
transmission service reservations of other areas in conjunction with the
Midcontinent Independent System Operator (MISO);
d. Performing transmission planning over a ten-year planning horizon;
e. Performing an annual assessment of the electric transmission system;
f. Developing selection criteria by which the transmission system configuration is
analyzed and performance evaluated;
g. Modeling and studying projected firm transfers over the range of forecast system
demands;
h. Performing analysis of reactive power resources to ensure adequate reserves exist
and are available to meet system performance criteria; and
i. Meeting NERC and RF Electric Reliability Compliance Standards for
Transmission Planning (applicable MOD and TPL standards).
1.2 Roles and Responsibilities
System Engineering is responsible for building models pursuant to steady state, short
circuit, and dynamic modeling and simulation pursuant to NERC Reliability
Standards MOD-010 and MOD-012 and pursuant to VEC-014 and VEC-008 as
stated in the above Purpose statement. Vectren also conducts simulation studies on
these models annually pursuant to the applicable TPL standards.
Midcontinent Independent System Operator (MISO) functions as Vectren’s
Reliability Coordinator (RC) and Planning Authority (PA).
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2 Electric Generation and Transmission Planning Procedure
2.1 Model Usage
2.1.1
Transmission Performance Planning Models (up to 10 years)
Models will be developed to cover critical system conditions and study years
as deemed appropriate. These include peak and off peak near-term (year 1 to
5) and long-term (year 6 to 10) models used for system growth, generator
interconnections, transmission interconnections, Load Serving Entity (LSE)
interconnections, and other studies as needed. The models are to be complete,
including existing facilities at or above 69 kV. The models may include
distribution circuits and substations as desired. Facilities included may be
uncommitted, but should represent, at a minimum, required upgrades, and may
include optimistic planned facilities. The models will be analyzed with More
Probable, Less Probable and Extreme Contingency events. The planning
horizon may be incremented further to consider future additions of any
available long-term transmission and/or generation plans. Longer term
models may also be required to study identified marginal conditions, proposed
generation additions, unavailability of long lead time equipment, or other
conditions that require longer lead time solutions.
2.1.2
AFC Planning models (0-3 years)
Models will be developed for determining the Available Flowgate Capability
(AFC) of facilities and impacts of both Firm and Non-Firm transmission
service requests. These models are to be developed with the Bulk Electric
System (all 100 kV and above existing and planned facilities) and certain 69
kV facilities, as required for proper transmission system modeling. All
committed facilities will be included for study periods in the future.
Uncommitted facilities will not be included. These models will be analyzed
with the More Probable and Less Probable Contingency events.
Vectren reviews models and identifies the most limiting contingencies for the
Vectren system or that significantly impact the Vectren system:
a. Facilities that show up as contingency overloads for the transfer studies;
and
b. Binding constraints identified by MISO in the real-time market.
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Facilities identified to be limits by Vectren are submitted as flowgates to
MISO for inclusion in their flowgate monitoring tool. See the MISO
Regional Transmission Organization (RTO) Reliability Plan. This plan
can be found on the MISO Web site
https://www.misoenergy.org/Library/Repository/Procedure/MISO%20Reliabil
ity%20Plan.pdf
Upon request, Vectren will provide flowgates to Transmission Service
Providers that work within Vectren’s Transmission Planning Area and to
adjacent Transmission Planners.
2.1.3
Operational models (current and next season)
Models will be developed for analyzing switching procedures, planned
transmission and generation outages, and contingencies for the current system
configuration. These models are also used for optimizing the system operation
and reducing losses. These models are to be complete, including all existing and
planned facilities at or above 69KV. These models may include distribution
circuits and substations as desired. The models will be available and current for
the upcoming season. These models will be analyzed with More Probable, Less
Probable and Extreme Contingency events.
2.2 Model Development
The Models have four critical elements that must be balanced to result in a viable
solution: A) the load, B) the generation, C) the system voltage, and D) the net
interchange. These are all tested against the equipment ratings and connectivity.
a. The peak forecasted real and reactive load is obtained from the Vectren Integrated
Resource Plan (IRP) and from other municipal and Local Balancing Area’s load
forecasts for each year. This load includes all transmission and distribution
losses. Losses for the distribution system will remain in the model load. The
model load will be reduced uniformly equal by the calculated value of the
transmission losses. Exceptions to this rule apply to identified non-conforming
loads (e.g. Alcoa, General Electric, Toyota, Waupaca). The modeled load
represents the expected steady state and dynamic behavior of loads that could
impact the study area. Off-peak or seasonal loads are calculated based on the
peak forecast load for that period. Interruptible load will be defined for
operational or AFC models, but will not be used for long-range planning. It is the
intent for long-range planning to serve all loads and not to utilize interruptible
load, since its long-term availability is uncertain. For stability analysis, the
system load is represented by a dynamic load model which models the expected
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dynamic load behavior of loads and considers the behavior of induction motor
loads.
b. The maximum available generation is also obtained from the IRP. Generation
resources (supply or demand side) will be dispatched as required to meet the
system load demand plus the system losses based a merit order dispatch set by
Vectren Power Supply. Sensitivity studies are normally conducted to represent
market based dispatch to determine if import capability is available in lieu of
running peaking turbines and select generation outages. Off-peak models are used
for export studies to determine the amount of export capability. Capacity Benefit
Margin (CBM) is studied upon request from a Load Serving Entity (LSE) or
Distribution Provider (DP). Automatic Reserve Sharing (ARS) provides the
capacity for the short-term and is controlled by the generation dispatch by MISO.
Studies for ARS are not normally conducted unless specifically initiated by a
request.
c. The bus voltages at generation plants are typically set to operate at or near 1.05
per unit of nominal voltage. Plant bus voltages are normally limited by the
generator terminal voltages on the high end and the auxiliary bus voltages on the
low end.
d. Long-term committed power transfers will also be included in the models as
needed and coordinated with the interchanging party. Contingency analysis may
require model imports of an additional 300MW for an outage of the largest unit,
or 570MW for the two largest units. Imports may also be used for additional
capacity and reserves during peak load. No generating unit will be modeled
above its rated capacity. Additional studies will be conducted by adjusting the
generation to determine the maximum import and export capability of the
transmission system.
e. Alcoa Warrick Operations generation and load is significant and is modeled in the
Vectren Control Area in MISO and RF models. Warrick has a transfer-trip
relaying scheme to automatically shed load (2 pot lines) for a trip of any of their
generators. Warrick generation and load is not included in the Vectren
contingency analysis. Vectren does not plan its system to directly support
Warrick operations. Studies at Alcoa Warrick Operations will be performed and
coordinated with Alcoa separately.
f. Models will include all reactive resources as applicable (generators, capacitors,
etc.).
g. Models will include, at a minimum, planned outages of six months or more of any
bulk electric equipment for the demand levels and time periods being studied.
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h. Applicable Ratings of all facilities will be included in the model. Ratings are
defined per VEC-014 Transmission and Generation System Facility Ratings.
i.
Sensitivity case(s) are developed to demonstrate the impact of changes to the
basic assumptions used in the model. To accomplish this, the sensitivity analysis
in the Planning Assessment must vary one or more of the following conditions by
a sufficient amount to stress the System within a range of credible conditions that
demonstrate a measurable change in System response.
i.
ii.
iii.
iv.
v.
vi.
vii.
Real and reactive forecasted Load.
Expected transfers.
Expected in service dates of new or modified Transmission Facilities.
Reactive resource capability.
Generation additions, retirements, or other dispatch scenarios.
Controllable Loads and Demand Side Management.
Duration or timing of known Transmission outages.
j. Steady state, short circuit, and dynamic equipment characteristics and system
simulation modeling data is maintained in System Engineering electronic files and
is used to create the appropriate Vectren system models for the various study
horizons.
k. Models are initially solved utilizing the automatic operation of load tap changing
(LTC) transformers and switched capacitors to reflect an optimized base case.
2.3 Model Evaluation Criteria
2.3.1
Contingencies
Our rationale for selected steady state contingencies is to include the entire
Vectren System and the facilities 3 buses, at a minimum, into all neighboring
control areas. Single contingencies include all facilities at or above 69kV and
double contingencies at 100kV or above internal to Vectren and all 69kV or
above ties. Our rationale for selected dynamics contingencies is close in faults
at power plants. Select 69kV facilities may be included for sensitivity studies.
The only exception is at Alcoa. Vectren planning models normally exclude
Alcoa Warrick operations contingencies for facility studies and for AFC
studies. Alcoa is a large aluminum smelter and rolling mill with normally
self-sufficient generation resources located on site. Improvements at Alcoa
will be studied and coordinated with Alcoa separately. The monitored
elements will include the entire Vectren System, Alcoa facilities, and three
buses, at a minimum, into all neighboring control areas. This should identify
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any problems induced into Alcoa and the other control areas that may be
caused by our system.
Special contingencies will be included in the appropriate severity category to
model the effects of existing and planned protection systems and control
devices (including any backup or redundant systems) and also to include any
concerns or conditions identified by Transmission System Operations (TSO).
The effects of existing and planned protection systems to be studied include
the removal of all elements protected by that protection system, the tripping of
generators when the generator bus voltage (or high side of the GSU bus
voltage) is less than the known or assumed generator steady state voltage limit
(or voltage ride-through capability), the tripping of all appropriate elements
when relay loadability limits are exceeded, successful and unsuccessful high
speed reclosing (in instances where high speed reclosing is utilized), tripping
of transmission elements when transient swings causes protection system
operation based on generic relay models, and any other effects as deemed
appropriate by Vectren’s System Engineering.
During the contingency analysis simulations, the models are solved allowing
the automatic operation of load tap changing (LTC) transformers. The
operation of the switched capacitors on Vectren’s system is a manual process;
therefor the automatic operation of the switched capacitors is disabled during
the simulation solution.
For the purpose of evaluating the transmission system, the following
contingency events are tested for both steady state and dynamic performance
per the NERC TPL requirements:
No Contingencies:
a. Normal system conditions per NERC Category P0 on the table found in
Appendix A.
More Probable Contingencies:
a. Sudden outage of any transmission facility (circuit, transformer, generator,
etc.) for normal system configuration per NERC Category P1 and P2 on
the table found in Appendix A. Vectren studies all Category B
contingencies in order to ensure studying the most severe.
Less Probable Contingencies:
a. Sudden outage of multiple transmission facilities (circuit, transformer,
generator, etc.) while the transmission system is reconfigured for any other
generator rated 200 MVA or more out of service.
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b. Additional NERC Category P3 through P7 contingencies as described on
the table found in Appendix A.
Extreme Contingencies:
Extreme contingencies are not expected to be caused by an electrical
disturbance, but rather are expected to be caused by a tornado, earthquake, ice
storm, or other catastrophic event. Mitigation measures may include the
following: redesign, modifications to substations, the use of ring busses,
breaker-and-a-half busses, or primary and secondary alternate busses to reduce
the possibility of an extreme contingency at that Substation.
Extreme Contingencies include:
a. Outage of a bus and any associated transformers at any substation with
three or more lines at 100 kV or above.
b. Additional NERC Extreme Events contingencies as described in the table
found in Appendix B.
2.3.2
Performance
Acceptable operating performance for the above contingencies is as follows:
For No Contingencies:
The system is stable and all facility loadings are within normal ratings and all
bus voltages are within normal limits.
For More Probable Contingencies:
After a sudden outage; however, before any operator directed system
adjustments are made, the system is stable and all facility loadings are within
normal ratings and all bus voltages are within normal limits. Any loss of
radial load is restored through routine operator directed switching procedures,
if possible.
For Less Probable Contingencies:
After a sudden outage; however, before any operator directed system
adjustments are made, the system is stable, all facility loadings are within
Emergency ratings and all bus voltages are within Emergency limits. Any loss
of load is restored through routine operator directed switching procedures, if
possible.
For Extreme Contingencies:
After a sudden multiple event outage; the remaining system is stable without
voltage collapse or loss of system integrity. The Vectren System may contain
an Island, or even be an Island itself to protect the Bulk Electric System.
Extreme Contingencies are used to ensure regional system stability, to identify
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weaknesses in the Vectren system, and to develop system restoration
procedures. The system will not be designed to completely eliminate the
effects of an extreme contingency, but the extreme contingencies should be
analyzed and steps should be taken to minimize both the probability of
occurrence and the resulting impact.
2.3.3
SOL and IROL Determination
All components of the BES facilities have a thermal and voltage rating. In
addition to these ratings, the system will be studied to determine if there are
any additional voltage or power stability issues which may further limit the
system. The System Operating Limits (SOLs) will be developed to operate
facilities within these ratings.
MISO has determined that Vectren does not have any IROLs. Vectren also
reviews system studies for potential IROLs through cascading analysis. If a
contingency occurs that results in a facility over 125% of its emergency rating,
or less than 90% voltage PU for generating facility, that facility will be
outaged. The simulation will be solved and again any facilities over 125% of
its emergency rating, or under 90% voltage PU for a generating facility, will
be outaged. Cascading occurs when more than two facilities, in a series, are
outaged using this process. This process will continue until no facilities
exceed this criterion to determine how many facilities will be affected and
outaged. This will be the determination of the extent of cascading.
If the initial post-contingent overloaded or undervoltaged BES facility is
subsequently outaged, and additional BES facilities are overloaded to over
125% of their emergency rating or below 90% voltage PU for a BES
generating facility, an IROL will be developed and coordinated with MISO
and other impacted systems.
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2.4 Study Results
Written study results will be presented in as clear and concise manner as possible
depending on the analysis being performed. The study results document all
assumptions made during the analysis, including the rationale behind the model
system conditions and year selection, and provide a summary of all contingencies
studied and the level of performance indicated by the model. The study results
include a reactive power resources review to indicate that adequate reactive resources
are available to meet system performance. If reactive resources are found to be
inadequate, a recommended plan will be provided as outlined in the next paragraph.
If the performance of the system does not meet requirements throughout the planning
horizons, a recommended corrective action plan including any system upgrades will
be provided. The written corrective action plan will include a schedule for
implementation with required in-service dates of facilities and with consideration for
expected lead times for equipment delivery and construction timelines. Corrective
action plans are not necessarily created to address deficiencies observed in a single
sensitivity study, however they are created if the same deficiency is identified in
multiple sensitivity studies throughout the assessment. These corrective action plans
are reviewed in subsequent planning assessments for continued validity and
implementation status.
An annual review is completed for each type of model listed in the “Model Usage”
section. Steady state, short circuit, and stability simulations will be performed if
changes to the bulk electric system conditions warrant analyses. Changes to the bulk
electric system that warrant such an analyses may include changes to generation,
transmission lines 100kv and above, or significant load change. System Engineering
will review subsequent annual assessments (where sufficient lead time exists) to
evaluate the continuing need for identified system facilities. Detailed implementation
plans are not needed. In instances where simulations were not performed due to lack
of system changes as described above, studies from past years are assessed to support
the current planning assessment, given that they are less than 5 calendar years old.
The short circuit portion of the analysis is used to determine whether circuit breakers
have adequate interrupting capability for faults that they will be expected to interrupt.
Any instance where a breaker’s interrupting capability is found to be inadequate is
documented in the corrective action plan along with the actions needed to achieve the
required system performance. These corrective action plans are reviewed in
subsequent planning assessments for continued validity and implementation status.
For the stability portion of the assessment, any instant where the system fails to meet
the performance requirements described in the MISO Business Practices Manual 020
(including acceptable damping, transient voltage response, etc.) will be considered to
show signs of instability, and these instances will be documented and addressed in
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corrective action plans. These corrective action plans are reviewed in subsequent
planning assessments for continued validity and implementation status.
The study results and corrective action plans will be documented and provided to
Vectren’s Reliability Coordinator (RC), Transmission Service Provider (TSP) and
Transmission Planning Coordinator (PC) annually. Vectren’s RC and TSP is
Midcontinent Independent System Operator (MISO). The study results will be
submitted by e-mail to MISO Real Time Operations (RTO), but any resulting projects
from the study will be submitted through the MISO WebTool.
Vectren’s PC is also MISO. The study results are e-mailed to MISO’s Transmission
Planners for inclusion in the MISO Transmission Expansion Plan (MTEP), but all
projects resulting from the study will be submitted through the Model On Demand
(MOD) software. The MTEP is posted publically and provided annually to the RRO.
Vectren also provides the study results to RF and upon request subject to
confidentiality requirements.
The study results and corrective action plans will be provided to Vectren TSO on a
timely basis for their review and inclusion into the planning process for reliable
operation of the transmission system during the study period.
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3 Cross References
Documents Cross Reference Table
Document Name
VEC-014 Transmission and Generation System Facility Ratings
MISO RTO Reliability Plan
MISO Transmission Expansion Plant (MTEP)
MOD-010
MOD-012
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References To
Document Name
1.2 Roles and
Responsibilities; 2.2 Model
Development
2.1.2 AFC Planning models
(0-3 years)
2.4 Study Results
1.2 Roles and
Responsibilities
1.2 Roles and
Responsibilities
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4 Appendices
4.1 Appendix A: Table 1 – Steady State & Stability Performance Planning Events
Table 1 – Steady State & Stability Performance Planning Events
Steady State & Stability:
a. The System shall remain stable. Cascading and uncontrolled islanding shall not occur.
b. Consequential Load Loss as well as generation loss is acceptable as a consequence of any event excluding P0.
c. Simulate the removal of all elements that Protection Systems and other controls are expected to automatically disconnect for each event.
d. Simulate Normal Clearing unless otherwise specified.
e. Planned System adjustments such as Transmission configuration changes and re-dispatch of generation are allowed if such adjustments are
executable within the time duration applicable to the Facility Ratings.
Steady State Only:
f. Applicable Facility Ratings shall not be exceeded.
g. System steady state voltages and post-Contingency voltage deviations shall be within acceptable limits as established by the Planning
Coordinator and the Transmission Planner.
h. Planning event P0 is applicable to steady state only.
i. The response of voltage sensitive Load that is disconnected from the System by end-user equipment associated with an event shall not be used to
meet steady state performance requirements.
Stability Only:
j. Transient voltage response shall be within acceptable limits established by the Planning Coordinator and the Transmission Planner.
Category
Initial Condition
Event1
Fault Type2
BES Level3
Interruption of
Firm
Transmission
Service Allowed
4
P0
No Contingency
Normal System
None
N/A
EHV, HV
No
P1
Single
Contingency
Normal System
Loss of one of the following:
1. Generator
2. Transmission Circuit
3. Transformer 5
4. Shunt Device 6
3Ø
EHV, HV
No
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NonConsequential
Load Loss
Allowed
No
9
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5. Single Pole of a DC line
SLG
1. Opening of a line
7
section w/o a fault
N/A
EHV
2. Bus Section Fault
P2
Single
Contingency
Normal System
SLG
P4
Multiple
Contingency
(Fault plus stuck
10
breaker )
Loss of generator
unit followed by
System
9
adjustments
Normal System
SLG
4. Internal Breaker Fault
8
(Bus-tie Breaker)
SLG
Loss of one of the
following:
1.Generator
2. Transmission Circuit
5
3. Transformer
6
4. Shunt Device
3Ø
5. Single pole of a DC line
SLG
Loss of multiple elements
caused by a stuck breaker10
(non-Bus-tie Breaker)
attempting to clear a Fault on
one of the following:
1.Generator
2. Transmission Circuit
3. Transformer5
4. Shunt Device6
5. Bus Section
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HV
EHV
8
3. Internal Breaker Fault
(non-Bus-tie Breaker)
P3
Multiple
Contingency
EHV, HV
No
9
No
No
9
No
Yes
No
9
12
Yes
No
HV
Yes
Yes
EHV, HV
Yes
Yes
EHV, HV
No
9
No
EHV
No
9
No
HV
Yes
12
SLG
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6. Loss of multiple
elements caused by a
stuck breaker10 (Bus-tie
Breaker) attempting to
clear a Fault on the
associated bus
P5
Multiple
Contingency
(Fault plus relay
failure to operate)
Normal System
P6
Multiple
Contingency
(Two overlapping
singles)
Loss of one of the
following followed
by System
adjustments.9
1.Transmission
Circuit
2. Transformer5
3. Shunt Device6
4. Single pole of a
DC line
P7
Multiple
Contingency
(Common
Structure)
Normal System
EHV, HV
Yes
EHV
No
HV
Yes
Yes
3Ø
EHV, HV
Yes
Yes
4. Single pole of a DC line
SLG
EHV, HV
Yes
Yes
The loss of:
1. Any two adjacent
(vertically or horizontally)
circuits on common
11
structure
2. Loss of a bipolar DC
line
SLG
EHV, HV
Yes
Yes
Delayed Fault Clearing due
to the failure of a nonredundant relay13 protecting
the Faulted element to
operate as designed, for one
of the following:
1.Generator
2. Transmission Circuit
3. Transformer5
4. Shunt Device6
5. Bus Section
Loss of one of the
following:
1. Transmission Circuit
5
2. Transformer
6
3. Shunt Device
Non-Public
SLG
9
Yes
No
SLG
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TRANSMISSION PLANNING
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4.2 Appedix B: Table 1 – Steady State & Stability Performance Extreme Events
Table 1 – Steady State & Stability Performance Planning Events
Steady State & Stability
For all extreme events evaluated:
a. Simulate the removal of all elements that Protection Systems and automatic controls are expected to disconnect for each Contingency.
b. Simulate Normal Clearing unless otherwise specified.
Steady State
Stability
1. Loss of a single generator, Transmission Circuit, single pole of a DC Line, 1. With an initial condition of a single generator, Transmission circuit, single
shunt device, or transformer forced out of service followed by another single pole of a DC line, shunt device, or transformer forced out of service, apply a
generator, Transmission Circuit, single pole of a different DC Line, shunt
3Ø fault on another single generator, Transmission circuit, single pole of a
device, or transformer forced out of service prior to System adjustments.
different DC line, shunt device, or transformer prior to System adjustments.
2. Local area events affecting the Transmission System such as:
2. Local or wide area events affecting the Transmission System such as:
a. Loss of a tower line with three or more circuits.11
a. 3Ø fault on generator with stuck breaker10 or a relay failure13 resulting in
b. Loss of all Transmission lines on a common Right-of-Way11.
Delayed Fault Clearing.
c. Loss of a switching station or substation (loss of one voltage level plus
b. 3Ø fault on Transmission circuit with stuck breaker10 or a relay failure13
resulting in Delayed Fault Clearing.
transformers).
c. 3Ø fault on transformer with stuck breaker10 or a relay failure13 resulting in
d. Loss of all generating units at a generating station.
Delayed Fault Clearing.
e. Loss of a large Load or major Load center.
d. 3Ø fault on bus section with stuck breaker10 or a relay failure13 resulting in
3. Wide area events affecting the Transmission System based on System
Delayed Fault Clearing.
topology such as: a. Loss of two generating stations resulting from
e. 3Ø internal breaker fault.
conditions such as:
f. Other events based upon operating experience, such as consideration of
i. Loss of a large gas pipeline into a region or multiple regions that have
initiating events that experience suggests may result in wide area
significant gas-fired generation.
disturbances
ii. Loss of the use of a large body of water as the cooling source for
generation.
iii. Wildfires.
iv. Severe weather, e.g., hurricanes, tornadoes, etc.
v. A successful cyber attack.
vi. Shutdown of a nuclear power plant(s) and related facilities for a day or
more for common causes such as problems with similarly designed plants.
b. Other events based upon operating experience that may result in wide area
disturbances.
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TRANSMISSION PLANNING
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4.3 Appendix C: Table 1 – Steady State & Stability Performance Footnotes (Planning Events and Extreme Events)
Table 1 – Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)
1. If the event analyzed involves BES elements at multiple System voltage levels, the lowest System voltage level of the element(s) removed for
the analyzed event determines the stated performance criteria regarding allowances for interruptions of Firm Transmission Service and NonConsequential Load Loss.
2. Unless specified otherwise, simulate Normal Clearing of faults. Single line to ground (SLG) or three-phase (3Ø) are the fault types that must
be evaluated in Stability simulations for the event described. A 3Ø or a double line to ground fault study indicating the criteria are being met is
sufficient evidence that a SLG condition would also meet the criteria.
3. Bulk Electric System (BES) level references include extra-high voltage (EHV) Facilities defined as greater than 300kV and high voltage (HV)
Facilities defined as the 300kV and lower voltage Systems. The designation of EHV and HV is used to distinguish between stated performance
criteria allowances for interruption of Firm Transmission Service and Non-Consequential Load Loss.
4. Curtailment of Conditional Firm Transmission Service is allowed when the conditions and/or events being studied formed the basis for the
Conditional Firm Transmission Service.
5. For non-generator step up transformer outage events, the reference voltage, as used in footnote 1, applies to the low-side winding (excluding
tertiary windings). For generator and Generator Step Up transformer outage events, the reference voltage applies to the BES connected voltage
(high-side of the Generator Step Up transformer). Requirements which are applicable to transformers also apply to variable frequency
transformers and phase shifting transformers.
6. Requirements which are applicable to shunt devices also apply to FACTS devices that are connected to ground.
7. Opening one end of a line section without a fault on a normally networked Transmission circuit such that the line is possibly serving Load
radial from a single source point.
8. An internal breaker fault means a breaker failing internally, thus creating a System fault which must be cleared by protection on both sides of
the breaker.
9. An objective of the planning process should be to minimize the likelihood and magnitude of interruption of Firm Transmission Service
following Contingency events. Curtailment of Firm Transmission Service is allowed both as a System adjustment (as identified in the column
entitled ‘Initial Condition’) and a corrective action when achieved through the appropriate re-dispatch of resources obligated to re-dispatch,
where it can be demonstrated that Facilities, internal and external to the Transmission Planner’s planning region, remain within applicable
Facility Ratings and the re-dispatch does not result in any Non-Consequential Load Loss. Where limited options for re-dispatch exist,
sensitivities associated with the availability of those resources should be considered.
10. A stuck breaker means that for a gang-operated breaker, all three phases of the breaker have remained closed. For an independent pole
operated (IPO) or an independent pole tripping (IPT) breaker, only one pole is assumed to remain closed. A stuck breaker results in Delayed
Fault Clearing.
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11. Excludes circuits that share a common structure (Planning event P7, Extreme event steady state 2a) or common Right-of-Way (Extreme
event, steady state 2b) for 1 mile or less.
12. An objective of the planning process is to minimize the likelihood and magnitude of Non-Consequential Load Loss following planning events.
In limited circumstances, Non-Consequential Load Loss may be needed throughout the planning horizon to ensure that BES performance
requirements are met. However, when Non-Consequential Load Loss is utilized under footnote 12 within the Near-Term Transmission Planning
Horizon to address BES performance requirements, such interruption is limited to circumstances where the Non-Consequential Load Loss
meets the conditions shown in Attachment 1. In no case can the planned Non-Consequential Load Loss under footnote 12 exceed 75 MW for
US registered entities. The amount of planned Non-Consequential Load Loss for a non-US Registered Entity should be implemented in a
manner that is consistent with, or under the direction of, the applicable governmental authority or its agency in the non-US jurisdiction.
13. Applies to the following relay functions or types: pilot (#85), distance (#21), differential (#87), current (#50, 51, and 67), voltage (#27 & 59),
directional (#32, & 67), and tripping (#86, & 94).
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