Comments of the
MISO Transmission Owners
Transmission Facilities
Not Subject to a
Federal Right-of-First-Refusal
Proposed Operations and Maintenance Qualifications
for
Incumbent and Non-incumbent
Transmission Developers
Comment [A1]: General Comment: The
Owners agree that there needs to be an ongoing
obligation on a project developer to operate and
maintain the facilities they build. However, the
Owners have several questions about this document
including: whether it imposes more stringent
requirements than are currently required by NERC;
who will be responsible to monitor and enforce these
requirements once a project is in service?
There does need to be some recognition by
developers of ongoing responsibilities, but this
document is overly detailed and prescriptive.
Draft White Paper
April 2012
2 Comments of the
MISO Transmission Owners
1. Definitions
Applicable Authority. The entity assigned to review and approve qualifications for
Transmission Developers to own, operate and maintain transmission facilities not subject to a
Federal right-of-first-refusal. This entity could be a state regulatory commission, MISO or
another entity.
New Substation. An entire Terminating Substation proposed within a specific transmission
project that does not exist prior to implementation of that transmission project. New
Substations do not include expansions to existing substations where substation expansions
include i) expanding or upgrading facilities within the substation footprint, ii) expanding the
substation footprint within the current site boundaries or iii) procuring additional land
adjacent to or near the existing substation site and expanding the substation footprint into or
adding substation facilities on the additional land.
State. A state or commonwealth within the United States or a province within Canada that
contains transmission facilities turned over to the functional control of the Midwest
Independent Transmission System Operator.
Tapped Substation. A distribution substation serving load that is tapped off of a
Transmission Circuit but is not considered a terminal of the Transmission Circuit and does
not include circuit breakers to isolate the Transmission Circuit when a short-circuit fault
occurs on the Transmission Circuit.
Terminating Substation. A substation located at one of the terminals of a Transmission
Circuit that contains one or more circuit breakers to automatically isolate the Transmission
Circuit when a short-circuit fault occurs on the Transmission Circuit.
Transmission Circuit. A high voltage DC or three-phase AC electrical circuit located
external to a substation and installed between two or more substations for the purpose of
transporting electrical energy between the substations.
Transmission Circuit Midpoint. For two terminal Transmission Circuits, the point on the
Transmission Circuit equidistant between the two terminals of the Transmission Circuit. For
three terminal Transmission Circuits (i.e., three-point lines), the point on the Transmission
Circuit where the three legs of the Transmission Circuit interconnect.
Transmission Line. One or more Transmission Circuits, or portions thereof, supported by
common structures if overhead or installed in common duct banks if underground. A
Transmission Circuit may consist of more than one Transmission Line.
3 Comments of the
MISO Transmission Owners
Transmission Developer. A pre-qualified i) incumbent Transmission Owner or ii) nonincumbent developer of transmission projects and subsequent owner of the associated
transmission facilities for any transmission facilities not subject to a Federal right-of-firstrefusal that are within the MISO footprint that have been turned over to the functional control
of MISO. Hereinafter generally referred to as the “entity”.
Type A Transmission Circuit. A Transmission Circuit not designated as a Type B
Transmission Circuit.
Type B Transmission Circuit. A Transmission Circuit that i) contains field switching
devices located external to a substation (e.g., gang-operated switches mounted on
transmission structures, etc.) and/or ii) connects to one or more Tapped Substations or other
loads or generators tapped directly off of the Transmission Circuit.
2. Introduction
This white paper outlines proposed operations and maintenance qualifications for entities that
plan to implement, own, operate and maintain transmission projects not subject to a Federal
right-of-first-refusal. The operations and maintenance qualifications proposed in this white
paper do not alter the obligations of incumbent Transmission Owners for transmission projects
that will remain subject to a right-of-first-refusal (i.e, as to which such right need not be
eliminated), including i) existing transmission facilities; ii) transmission facilities approved for
construction in an MTEP planning cycle prior to the first MTEP planning cycle where the rightof-first-refusal will be implemented to the extent applicable and iii) implementation of future
transmission that will continue to be subject to a right-of-first-refusal.
The operations and maintenance requirement represented by the qualifications proposed in this
white paper apply to entities after the facilities are placed in service. Requirements to implement
transmission projects prior to the in-service date and requirements for project bids are discussed
in separate white papers.
This white paper introduces independent qualifications for i) operating and maintaining
Transmission Line facilities and ii) operating and maintaining New substation facilities.
Ownership of Transmission Line facilities after the facilities are in service requires compliance
with i) above and ownership of New substation facilities after the facilities are in service requires
compliance with ii) above. Ownership of Transmission Lines and New substation facilities
requires compliance with both i) and ii) above. All operations and maintenance qualifications
will be applied on a State by State basis, and it is possible that a specific entity could be qualified
in one State and not be qualified in another State, or the level of qualification (i.e., ability to own,
operate and maintain substations vs. Transmission Lines vs. both types of facilities) could vary
from State to State as well.
4 Comments of the
MISO Transmission Owners
The remainder of this white paper is organized into the following sections:


Transmission Line Facility Operations and Maintenance Qualifications
New Substation Facility Operations and Maintenance Qualifications
The proposed point of demarcation between “Transmission Line facilities” and “substation
facilities” is assumed to be a vertical plane located somewhere between i) the property boundary
of the tract of land owned or leased by the substation owner that contains the substation and ii)
the substation footprint (the ground grid footprint or fence if the ground grid does not extend
beyond the fence). Provisions will be needed to adjust the point of demarcation when future
substation expansions requiring additional land or an expanded footprint are developed.
3. Transmission Line Facility Operations and Maintenance Qualifications
Transmission Line facility operations and maintenance qualifications are organized as follows:
i) Transmission Circuit forced outage response, ii) Transmission Circuit switching, iii)
Transmission Line spare parts, iv) Transmission Line emergency repair, v) Transmission Line
preventative maintenance program and vi) Transmission Line modeling and records. These
qualifications are discussed below:
3.1. Transmission Circuit Forced Outage Response
A Transmission Circuit forced outage is defined as the automatic or manual removal of a
Transmission Circuit from service due to i) a permanent short-circuit fault, ii) a
temporary short-circuit fault that persists through the entire reclosing cycle, iii) a shortcircuit fault in another zone of protection where operation of remote backup protection
or breaker failure protection was necessary, iv) a power system swing, v) an overload on
the Transmission Circuit, vi) manual removal of a Transmission Circuit from service due
to an imminent short-circuit fault or to mitigate a potential safety issue or vii) false
operation of a protective relay scheme. Momentary outages where reclosing is
successful will not be considered forced outages for the purpose of these qualifications.
In cases where the Transmission Circuit is removed from service due to i) a short-circuit
fault in another zone of protection (i.e., operation of remote backup protection or breaker
failure protection), ii) a power system swing, iii) an overload on the Transmission
Circuit or iv) false operation of a protective relay scheme, these situations represent
system operational problems not directly related to the specific Transmission Circuit,
and thus there is generally no forced outage response required by the entity to address
issues specific to the Transmission Circuit. In cases where the Transmission Circuit is
removed from service due to i) a permanent short-circuit fault, ii) a temporary shortcircuit fault that persists through the entire reclosing cycle or iii) manual removal due to
an imminent short-circuit fault or to mitigate a potential safety issue, these situations
5 Comment [A2]: Owner Comment: Too
detailed. This should just say that a forced outage is
the unplanned automatic or manual removal of a
Transmission Circuit where automatic reclosing is
not successful.
Comment [A3]: Owner Comment: Delete.
Unnecessary.
Comments of the
MISO Transmission Owners
represent issues directly related to the specific Transmission Circuit, and thus the entity
must respond to troubleshoot and correct the problem so that the Transmission Circuit
can be returned to service as soon as possible.
The entity must have someone on call on a 24/7 basis to initiate the entity’s forced
outage response plan. In addition, the entity must have in place some method to detect
forced outages on Transmission Circuits (e.g., if the entity does not own the Terminating
Substations, they will likely need to work out an agreement with the owners of these
substations to monitor the Transmission Circuit on their behalf and contact and update
their on-call personnel upon a forced outage, etc.)
Upon detection or notification of a forced transmission outage on one or more
Transmission Circuits owned by the entity, the entity will immediately initiate forced
outage response for the Transmission Circuit(s) in accordance with the Transmission
Circuit forced outage response plan. Transmission Circuit forced outage response plans
must be developed for each State where a entity owns or operates one or more
Transmission Line facilities and must be approved by the Applicable Authority. Each
Transmission Circuit forced outage response plan should be updated monthly (??) and
forwarded to the Applicable Authority within five (??) business days. The Transmission
Circuit forced outage response plan should include the following components:



Call-out plan List of entity personnel or contractors assigned to provide
emergency response to forced Transmission Circuit outages including
contact information of all assigned personnel and at least two on-call
employees for each contractor.
There should be at least one employee or contractor that has access to a
helicopter that can be used to fly the Transmission Circuit if the circuit
length exceeds 20 (??) miles. This employee or contractor must be
available to commence air patrols with 24 (??) hours notification if a Type
A Transmission Circuit or 4 (??) hours notification if a Type B
Transmission Circuit.
If contractors are used for emergency response, the list of contractors must
include at least two contractors able to begin ground patrols with 24 (??)
hours notification if a Type A Transmission Circuit or 4 (??) hours
notification if a Type B Transmission Circuit. The plan must list the
location of the base of operations for each of these contractors and an
explanation of how they will satisfy the response time requirements if
located more than 250 (??) miles from the Transmission Circuit Midpoint
6 Comment [A4]: Owner Comment: Some
Owners use both “on call” procedures and
employees subject to “call-out.” The difference is
significant because as many times first responders
are employees subject to call-out (they drive their
trucks home) as opposed to being “on-call,” which
means something different in terms of requirements
to respond. These Owners would prefer a note here
indicating that call-outs are allowed as well as oncall.
Comment [A5]: Owner Comment: Delete. Not
necessary to review/update monthly. This should
simply say that if it is updated, it needs to be
forwarded to MISO in 10 business days.
Comment [A6]: Owner Comment: Would
MISO actually need the names of the personnel, or
would a telephone number that is monitored suffice?
Comment [A7]: Owner Comment: It is not
necessary to provide a list of names of entity
personnel, maybe just the number of approved staff
level that respond to emergency forced transmission
line outages.
Comment [A8]: Owner Comment: This should
not be restricted to helicopters. Other aerial patrols
are used.
Comment [A9]: Owner Comment: Should be
the same as for Type B.
Comment [A10]: Owner Comment: This
requirement should be eliminated. Poor weather can
prevent this response. As long as there is a plan to
restore in a timely fashion, that should be sufficient.
Also, we do not adhere to these times today.
Comment [A11]: Owner Comment: Don’t
differentiate between Type A & B. Both should be
24 hours.
Comment [A12]: Owner Comment: Should be
the same as for Type B.
Comment [A13]: Owner Comment: Don’t
differentiate between Type A & B. Both should be
24 hours.
Comments of the
MISO Transmission Owners
if a Type A Transmission Circuit or more than 50 (??) miles from the
Transmission Circuit Midpoint if a Type B Transmission Circuit.


If personnel are used for emergency response, personnel must be available
to commence line patrolling within 24 (??) hours if a Type A
Transmission Circuit or 4 (??) hours if a Type B Transmission Circuit.
The plan must list the location of the base of operations for forced outage
response personnel and an explanation of how they will satisfy the
response time requirements if located more than 250 (??) miles from the
Transmission Circuit Midpoint if a Type A Transmission Circuit or more
than 50 (??) miles from the Transmission Circuit Midpoint if a Type B
Transmission Circuit.
The Transmission Circuit forced outage response plan should include
Pprocedures for coordinating with the owners of the Terminating
Substations, owners of other sections of the Transmission Circuit and, if a
Type B Transmission Circuit, owners of Tapped Substations to i) obtain
clearance, ii) obtaining headway and iii) obtaining information from fault
recording devices and digital relays with fault locating algorithms installed
in the Terminating Substations.

The entity is expected to have procedures in place to maximize the use of
information provided by fault recorders and fault locating relays in
Terminating Substations whether or not they own the Terminating
Substations.

When the cause of the forced outage is determined, the entity should
initiate the process to make Eemergency repair plans in accordance with
the Transmission Line emergency repair qualifications outlined in Section
3.4 unless a major storm/event (e.g., hurricane, etc.) for the corresponding
geographic area has been declared by MISO, in which case emergency
repairs should be initiated as soon as practical based on the relative
priority of the forced outage with respect to other forced outages.

Plan for coordinated operations with other Transmission OwnersIf no
forced outage cause is found, the entity should have procedures included
in the Transmission Circuit forced outage response plan to work with the
owners of the Terminating Substations (if different than the entity),
owners of other sections of the Transmission Circuit and, if a Type B
Transmission Circuit, owners of Tapped Substations to attempt to place
7 Comment [A14]: Owner Comment: Don’t
differentiate between Type A & B. Both should be
24 hours.
Comment [A15]: Owner Comment: What does
this mean?
Comments of the
MISO Transmission Owners
the Transmission Circuit back in service in a manner that minimizes risks
to personnel and public safety, equipment damage and adverse impacts on
BES reliability.
3.2. Transmission Circuit Switching
Qualifications to perform Transmission Circuit switching applies only to entities that
own one or more Type B Transmission Circuits within a given State since Type A
Transmission Circuits contain no switching devices by definition. Type B Transmission
Circuits may contain field switches (i.e., switches not located within substations)
installed for sectionalizing purposes that must be operated by the entity. Examples of
this situation include i) switches located on structures near the point where a radial tap
extends from the Transmission Circuit to feed a load or distribution substation, ii)
switches on either side of a Tapped Substation in situations where these switches cannot
be installed within the Tapped Substation due to space or other limitations or iii)
switches on each leg of a three-terminal line located at or near the Transmission Circuit
Midpoint.
For a forced outage of the Transmission Circuit or for other operational reasons, timely
switching may be required to ensure Bulk Electric System reliability and to minimize the
duration of service interruptions to customers. Switches in series with the Transmission
Circuit and located within a Tapped Substation will normally be owned and operated by
the owner of the Tapped Substation (e.g., Load Serving Entity), but there could be
arrangements where the entity owns and operates these switches or operates these
switches on behalf of the Tapped Substation owner via an agreement, in which case the
corresponding Transmission Circuit must be designated as a Type B Transmission
Circuit. If all sections of a Type B Transmission Circuit that contain switching devices
are owned and operated by other owners, then the Transmission Circuit qualifications
will not be applicable to the entity for their portion of the Transmission Circuit.
Transmission Circuit switching policies must be developed for each State where a entity
owns or plans to own a Type B Transmission Circuit and must be approved by the
Applicable Authority. Each Transmission Circuit switching policy should be updated
monthly (??) and forwarded to the Applicable Authority within five (??) business days.
The Transmission Circuit switching policy must contain the following components:

A NERC certified system operator with Reliability Coordinator
certification or Transmission Operator certification switching supervisor
employed by the entity must be available on a 24/7 basis to write and issue
switching orders. The switching supervisor can be on-call or working on a
8 Comment [A16]: Owner Comment: There is
no need to update this monthly.
Comments of the
MISO Transmission Owners
shift. There is no limitation on the location of the switching supervisor
other than he/she must be based within the continental United States. The
switching supervisor should be qualified to write and issue transmission
switching orders through successful completion of a certified training
program. The switching supervisor must maintain contact information to
communicate with other asset owners, including but not necessarily
limited to, owners of the corresponding Terminating Substations, owners
of any Tapped Substations along the Transmission Circuit and owners of
other sections of the Transmission Circuit if various sections are owned by
different entities. The switching supervisor must maintain up-to-date
copies of detailed one-line switching diagrams of all owned Type B
Transmission Circuits that are either entirely under his/her jurisdiction or a
portion thereof, as well as detailed one-line switching diagrams for all
corresponding Terminating Substations and Tapped Substations regardless
of who owns these substations. The switching supervisor may or may not
be the same individual that initiates the entity’s forced outage response
plan. To ensure safety and reliability, prior to issuing any switching
orders, the switching supervisor shall coordinate with the switching
supervisors on duty that have switching jurisdiction over corresponding
Terminating Substations and, if applicable, Tapped Substations and other
sections of the Transmission Circuit owned by other entities to obtain the
current status of all switching devices within these substations and along
the entire Transmission Circuit. The switching supervisor will coordinate
issuance of switching orders with these other switching supervisors
including updates when switching orders have been completed.


List of entity personnel assigned to operate field switches including
contact information of all assigned personnel and at least two on-call
employees that can immediately respond. Field switching personnel
should be qualified to execute transmission switching orders through a
certified training program. Contractors are not permitted to be used for
operation of field switches. Personnel used for field switching should be
available to commence field switching with 4 (??) hours of notification.
The Transmission Circuit switching policy must list the location of the
base of operations for switching personnel and an explanation of how they
will satisfy the response time requirements if located more than 50 (??)
miles from any Transmission Circuit Midpoint.
Procedures for non-emergency switching to facilitate planned maintenance
outages or restore service following emergency repairs must be included
9 Comment [A17]: Owner Comment: Delete.
This is covered if the operator is certified.
Comment [A18]: Owner Comment: This
seems too short. Many lines are more than 100
miles.
Comment [A19]: Owner Comment: Lists
would be impossible to keep up with. Contractors
must be allowed to switch. Also, does a “certified”
training program exist? Also, it is unclear whether
entities could meet the time criteria.
Comments of the
MISO Transmission Owners
in each entity’s Transmission Circuit switching policy. These procedures
should ensure coordination between the entity and the owners of the
corresponding Terminating Substations, Tapped Substations and other
sections of the Transmission Circuit for each Type B Transmission
Circuit, including i) coordination of switching order issuance, ii) updates
on switching completion and iii) development of an overall switching
strategy and sequence that takes into consideration both the switching
device type (e.g., substation circuit breaker with relays, air-break switch
with vacuum interrupter attachments, air-break switch with arcing horns,
hook stick disconnects, etc.) and the switching operation type (e.g.,
making or breaking parallel, interrupting charging current, interrupting
load when necessary, energizing a dead line, etc.) to ensure the appropriate
switching devices are used to perform the appropriate switching tasks.

Any clearance or headway issued must be issued to an employee of the
entity even if the work is performed by a contractor. It will be the
responsibility of this employee to release clearance or headway when
he/she has verified conditions are acceptable for releasing clearance and/or
headway.
3.3. Transmission Line Spare Parts
For each Transmission Line owned by an entity, the entity must maintain sufficient spare
parts in inventory to make emergency repairs within a reasonable time frame. The
quantity of spare parts to be maintained should be sufficient to rebuild the longest span
of a Transmission Line between double dead-end structures for all Transmission Lines
owned by the entity within a given State. To reduce inventory carrying costs and speed
restoration of service following a major forced outage, it is not necessary to use the same
line design for emergency repairs so long as any reduced rating is coordinated with the
MISO andi) the normal and emergency Transmission Circuit ratings are not reduced, ii)
the line design complies with regulatory requirements and iii) the line design complies
with all applicable standards and codes including, but not limited to, NERC reliability
standards, regional reliability standards and the National Electric Safety Code.
However, the entity will be required to restore the Transmission Line to its original
design within one year of the forced outage via one or more planned outages.
For example, if a 345 kV single-circuit Transmission Line is designed using steel lattice
towers and bundled 954 ACSR conductor sagged at 125 degrees C, and a tornado
destroys seven spans of the line between double-dead end structures, it is permitted to
replace the damaged line section on a temporary basis with bundled 336 ACSS
10 Comment [A20]: Owner Comment: How does
this compare with the requirements below to have 3
tangent structures, one double deadend, etc.?
In addition, the statement “all Transmission Lines”
could be read to mean that an entity needs to be able
to back up 100% of its lines for a single event which
is surely not the intent. It would be better to limit the
number of concurrent line outages to be backed up
with some sort of clarifying phrase.
Comment [A21]: Owner Comment: What does
this mean? Is it necessary?
Comments of the
MISO Transmission Owners
conductor sagged at 200 degrees C and installed on guyed wood H-frame structures so
long as the temporary replacement complies with all applicable regulatory requirements,
reliability standards and construction codes. In this example, the damaged line section is
temporarily replaced with an alternative design that has comparable ratings, but higher
impedance and losses, and perhaps higher long-term maintenance requirements. In this
example, the entity is obligated to replace the temporary line section with a permanent
line section built according to the original design (rating, impedance, structure design,
etc.) and using materials comparable to or superior to the original design within one year
of the forced outage.
At a minimum, an entity should carry sufficient inventory at all times to completely
replace three tangent structures, one running angle structure, one double dead-end
structure and one angle dead-end structure for each original structure design (steel
lattice, steel H-frame, wood H-frame, steel pole, wood pole, etc.) owned by the entity
within a State. This inventory should include insulators, connectors and all other
materials (e.g., attachment hardware, guying materials, grounding materials, stub poles,
anchor bolts, etc.) required for complete structure replacement, and allowances should
be made to maintain sufficient inventory for variations in structure or pole heights and/or
pole classes. In addition, at a minimum, the entity should maintain sufficient inventory
to replace five spans of conductor and shield wire for each conductor and shield wire
type and size used within a State per the original design.
The location of spare parts must be maintained such that the parts are available on site
with 24 (??) hours notice. For small parts such as attachment hardware and connectors,
materials can be stored anywhere within the continental United States so long as they
can be shipped on site with 24 (??) hours notice. For larger parts such as suspension or
strain insulator units, poles, crossarms, davit arms, structure assemblies or conductor
reels, the spares parts policy should contain an explanation of how the response time
requirements will be met if the parts are stored at a location more than 250 (??) miles
from the Transmission Circuit Midpoint. The entity is expected to maintain a spare parts
policy for each State listing minimum inventory levels, storage locations and emergency
transportation procedures and arrangements. Each policy must be approved by the
Applicable Authority. Each policy should be updated quarterly (??) and a copy provided
to the Applicable Authority within five (??) business days.
With regard to planned maintenance outages, the entity should arrange to have all
materials in hand prior to switching out the Transmission Circuit to avoid an excessive
planned outage duration. These materials should be located on site at the time the
Transmission Circuit is switched out of service.
11 Comment [A22]: Owner Comment: How does
this compare with the requirements below?
Comments of the
MISO Transmission Owners
3.4. Transmission Line Emergency Repair
Transmission Line emergency repair includes fixing or replacing one or more failed
components on a Transmission Line or clearing a permanent short-circuit fault from a
Transmission Circuit. Transmission Line maintenance and repair is generally initiated
as a result of a forced outage or a report from the public on an abnormal or unsafe
condition associated with a Transmission Line.
The entity should have in place a Transmission Line emergency repair policy for each
State where the entity owns Transmission Line facilities that outlines practices and
procedures for making emergency repairs to Transmission Lines. Each Transmission
Line emergency repair policy must be approved by the Applicable Authority. Each
Transmission Line emergency repair policy should be updated quarterly (??) and a copy
provided to the Applicable Authority within five (??) business days. The Transmission
Line emergency repair policy should include the following:

List of personnel or contractors assigned to provide emergency repair
services including contact information of all assigned personnel and at
least two on-call employees for each contractor.

If contractors are used for emergency repair, the list of contractors should
include at least two contractors available to commence emergency repair
work with 24 (??) hours notification if a Type A Transmission Circuit or 4
(??) hours notification if a Type B Transmission Circuit. The
Transmission Line emergency repair policy must list the location of the
base of operations for each of these contractors and an explanation of how
they will satisfy the response time requirements if located more than 250
(??) miles from the Transmission Circuit Midpoint if a Type A
Transmission Circuit or more than 50 (??) miles from the Transmission
Circuit Midpoint if a Type B Transmission Circuit. Contractors
performing emergency maintenance should have ten years experience
maintaining and constructing transmission and distribution lines.

If entity personnel are used for emergency repair work, personnel should
be available to commence emergency repair work with 24 (??) hours
notification if a Type A Transmission Circuit or 4 (??) hours notification if
a Type B Transmission Circuit. The Transmission Line emergency repair
policy must list the location of the base of operations for emergency repair
personnel and an explanation of how they will satisfy the response time
requirements if located more than 250 (??) miles from the Transmission
12 Comment [A23]: Owner Comment: It is not
necessary to update this quarterly.
Comment [A24]: Owner Comment: This
section looks like a repeat of Section 3.1
requirements.
Comments of the
MISO Transmission Owners
Circuit Midpoint if a Type A Transmission Circuit or more than 50 (??)
miles from the Transmission Circuit Midpoint if a Type B Transmission
Circuit.


When abnormal conditions are reported by the public, Pprocedures to
inspect should be in place to have the condition of the facilityinspected by
an entity representative (employee or contractor) within a reasonable
amount of time (not more than eight (??) hours) or arrangements should be
made with the Terminating Substation owners ahead of time to deenergize the Transmission Circuit(s) until such time as the entity can
inspect the Transmission Line. When unsafe conditions are reported (e.g.,
live conductors near the ground, pole fire, etc.), procedures should be in
place for the Terminating Substation owners to immediately de-energize
the Transmission Circuit(s) without prior permission of the entity.
The Transmission Line emergency repair policy should list the types of
tools and equipment needed for emergency repair including vehicles,
heavy equipment, live line tools, conventional tools, rubber goods and
other required tools and equipment. The policy should state if this
equipment is owned by the entity, the contractor or another entity and the
emergency procedures for obtaining the equipment if not owned by the
entity or contractors.
3.5. Transmission Line Preventative Maintenance Program
Transmission Line preventative maintenance includes patrolling and inspecting
Transmission Lines on a routine schedule, identifying maintenance requirements and
scheduling maintenance work to fix or replace components as necessary to minimize the
probability of a forced Transmission Circuit outage or correct an unsafe condition. The
entity shall develop a Transmission Line preventative maintenance plan for each State
that must be approved by the Applicable Authority. The Transmission Line preventative
maintenance plan should be updated annually (??) and a copy provided to the Applicable
Authority within ten (??) business days. Each Transmission Line preventative
maintenance plan should outline specific Transmission Line patrol and inspection cycles
and methods, including patrol methods (e.g., air vs. ground patrols), use of specialty
contractors for specialized inspections (e.g., wood pole inspections, etc.) and/or use of
any special inspection equipment (e.g., infrared equipment, etc.). Each Transmission
Line preventative maintenance plan should list the personnel or contractors that will be
used to perform preventative maintenance, and an overall schedule of inspection and
patrol activities.
13 Comment [A25]: Owner Comment: Does this
present a CIP issue?
Comments of the
MISO Transmission Owners
The results of the preventive maintenance inspections and patrols should be used to
schedule maintenance work, including like-for-like capital replacements of FERC
retirement units (e.g., replacement of a transmission structure, etc.), to avoid forced
outages and/or unsafe operating conditions. Non-emergency repairs should be scheduled
within a reasonable time frame, but not more than 90 (??) days from the date of the
inspection. Emergency repair work identified during a preventative maintenance
inspection should be scheduled within 24 (??) hours or as soon as practical thereafter.
The preventative maintenance plan must also include a vegetation management plan,
including cycles for trimming trees to ensure appropriate clearance at all times, mowing
or bush hogging rights-of-way, removing vegetation growth from poles or structures and
routine inspections of right-of-ways to identify and tag for removal danger trees (dead
trees or leaning trees that could potentially fall into a Transmission Line) that represent
an elevated risk of a forced Transmission Circuit outage. The vegetation management
plan should be developed to comply with applicable NERC and regional reliability
standards (e.g., NERC FAC-003, etc.).
There should be procedures in place for the entity to coordinate planned maintenance
outages with the MISO, Terminating Substation owners and, if applicable, Tapped
Substation owners and owners of other sections of the Transmission Circuit including
requests for clearance or headway from these other entities to perform non-emergency
maintenance work. For non-emergency maintenance work, the entity may use personnel
or contractors, and there is no requirement on the location of their base of operations
other than it be in the continental United States. Planned maintenance outages, including
issuance of clearance and/or headway, should not commence prior to the time when the
maintenance and repair crews are on site and ready to work to minimize the duration of
the planned maintenance outage. When practical, clearance or headway should be given
up at the end of each workday so that the Transmission Circuit can be returned to service
and/or reclosing can be enabled until work is scheduled to begin again. Contractors
performing non-emergency maintenance should have ten years experience maintaining
and constructing transmission and distribution lines or, if a specialty contractor such as a
foundation contractor, ten years of experience in their specialty area.
3.6. Transmission Line Modeling and Records
An entity must maintain models of all Transmission Circuits that can be used in power flow
simulations, dynamic simulations, production cost modeling simulations and short-circuit
simulations. These models must include load information for any loads tapped off of a Type
B Transmission Circuit. Model updates for power flow simulations, dynamic simulations
14 Comment [A26]: Owner Comment: Doesn’t
MISO already have these?
Comment [A27]: Owner Comment: Not sure if
this rules out some of the contractors that some
Owners use.
Comments of the
MISO Transmission Owners
and production cost modeling simulations must be forwarded to MISO using the Model on
Demand (MOD) application. Model updates for short-circuit simulations, which include
positive and zero sequence models for Transmission Circuits, should be submitted to MISO
and the entity responsible for performing short-circuit analysis in the area.
The entity must maintain as-built records for each Transmission Line facility and must
update these records when changes are made. The as-built records include, in addition to
models, i) as-built one-line switching diagram of all Transmission Circuits, ii) as-built planprofile drawings for all Transmission Lines and iii) as-built right-of-way cross section
elevation drawings keyed to the plan-profile drawings. The switching diagram should show
all terminals, legs, radial taps, Tapped Substations, switches and arresters. The switching
diagram should indicate mileages, conductor information and impedances for each section of
the Transmission Circuit. The entity should retain the original detailed engineering
documentation for each Transmission Line for the life of the facility.
The entity must also maintain sufficient records to produce and maintain an accurate
Attachment O including information on plant and all applicable expenses. The entity should
maintain i) records on forced outages, ii) switching records, iii) emergency repair records and
iv) preventative maintenance records regarding inspections and maintenance work for a
period of five (??) years. The entity should maintain up-to-date records on all spare parts
inventory levels. The entity should retain copies of the current and previously filed policies
with the Applicable Authority.
Comment [A28]: Owner Comment: This is not
a qualification criteria. It is a more of a requirement
for TOs, and should be removed from a qualification
document. Also, this is more of a transmission
planner role, as opposed to Owner? The entity will
have to provide the physical parameters of its
equipment, but others are more likely to have load
and prod cost data.
Comment [A29]: Owner Comment: This is not
a qualification criteria. It is a more of a requirement
for TOs, and should be removed from a qualification
document. Maybe the more appropriate place for
this is in a process document.
Comment [A30]: Owner Comment: This is not
appropriate for this document.
4. New Substation Facility Operations and Maintenance Qualifications
New Substation facility operations and maintenance qualifications are organized as follows: i)
substation real-time operations, ii) substation forced outage response, iii) substation switching,
iv) substation emergency testing and repair, v) substation spare parts and equipment, vi)
substation preventative maintenance program and vii) substation modeling and records. These
qualifications are discussed below:
4.1. Substation Real-Time Operations
Entities that own New Substations must providehave a real-time operations center staffed
on a 24/7 basis and located within the continental United States. The purpose of the realtime operations center is to monitor substation facilities on a real-time basis, monitor and
control voltages, monitor and control power flows on selected facilities, provide real-time
telemetry on the transmission system and initiate emergency and non-emergency
response when required. Specifically, substation owners will need to provide the
following real-time functions for substation facilities which they own, operate and
maintain:
15 Comment [A31]: Owner Comment: It seems
like this service could be contracted out.
Comments of the
MISO Transmission Owners



Meet MISO data specs and communication requirements
Entities that own New Substations should have in place a Supervisory Control
and Data Acquisition (SCADA) system that monitors electrical quantities,
equipment status and equipment condition remotely. Entities must telemeter real
power flows on all tie lines and update the appropriate balancing authorities on a
four second basis to facilitate continuous calculation of the applicable Area
Control Errors (ACE). Substation owners should also meter real and reactive
power flows on all tie lines using settlement quality meters for use in tracking
actual interchange. Substation owners should telemeter real and reactive power
flows and current flows by phase on all Transmission Circuits, power
transformers and circuit breakers as well as voltages levels at all buses both for
their own use and for use in state estimation by MISO and other applicable
entities. Substation owners must remotely monitor circuit breaker status (open or
closed), reclosing status (enabled or disabled), status of shunt capacitor and
reactor banks, status of series capacitor and reactor banks when they are
switchable and tap positions on automatic load tap changers, voltage regulators
and phase angle regulators both for their own use and for use in state estimation
by MISO and other applicable entities. Substation owners are highly encouraged
to also remotely monitor the condition of substation equipment by monitoring
selected equipment parameters or parameter alarms such as SF6 circuit breaker
gas pressure or density, transformer top oil temperature, transformer winding
temperature, transformer liquid level, transformer vacuum pressure, transformer
pump flow indicators, digital relay alarms, lockout relay status, relay targets,
transformer nitrogen bottle pressure, battery voltage, circuit breaker trip coil
continuity and other equipment parameters. At a minimum, a SCADA monitored
station alarm should be established to trigger when monitored equipment
parameters are abnormal or in an alarm state so that field personnel can be
dispatched to investigate and, if applicable, correct.
The operations center must provide Entities that own New Substations should
have in place a 24/7 staff at their real-time operations center to monitor bus
voltages and power flows and i) remotely switch shunt reactors and capacitors in
and out of service, ii) remotely switch series reactors and capacitors as necessary,
iii) remotely control static VAR compensators (SVCs) and iv) remotely change
tap positions on phase angle regulators, voltage regulators and automatic load tap
changers that are not controlled via automatic controls. Remote operation of
equipment such as capacitors, reactors, SVCs and tap changing equipment should
be in accordance with NERC and regional reliability standards, operating
16 Comment [A32]: Owner Comment: This may
be more of a requirement than a qualification.
Comment [A33]: Owner Comment: Needs to
be NERC certified staff. Possible that the entity
could contract this out to a NERC certified operator.
Comments of the
MISO Transmission Owners
agreements and voltage and power flow schedules and should be coordinated
with other transmission owners in the area and MISO.

EMS Staff to respond to EMS and communication system outages.

The operations center must provide Entities that own New Substations should
have in place a 24/7 staff at their real-time operations center to write and issue
switching orders in accordance with the substation switching qualifications
outlined in Section 4.3, initiate forced outage emergency response for facilities
within their substations and or Transmission Circuits that terminate at their
substations, whether or not these terminating Transmission Circuits are facilities
they own, operate and maintain. The 24/7 staff at their operations center should
also initiate response to substation alarms and other abnormal conditions at the
substation detected by the SCADA system.
Comment [A34]: Owner Comment: Needs to
be NERC certified staff. Possible that the entity
could contract this out to a NERC certified operator.
4.2. Substation Forced Outage Response Criterion
A substation forced outage is defined as the automatic or manual removal of any facility
within the substation or any Transmission Circuit that terminates at the substation from
service. due to i) a permanent short-circuit fault, ii) a temporary short-circuit fault that
persists through the entire reclosing cycle, iii) a short-circuit fault in another zone of
protection where operation of remote backup protection or breaker failure protection was
necessary, iv) a power system swing, v) an overload on a transmission facility, vi)
manual removal of a transmission facility from service due to an imminent short-circuit
fault or to mitigate a potential safety issue or vii) false operation of a protective relay
scheme. Momentary outages where reclosing is successful will not be considered forced
outages for the purpose of this qualification. Entities must have someone on call on a
24/7 basis to receive calls from their real-time operations center to initiate the entity’s
substation forced outage response plan.
Upon notification of a forced transmission outage on one or more facilities within a
substation or one or more Transmission Circuits that terminate at a substation owned by
the entity, the entity will immediately put into place its substation forced outage
response plan. Substation forced outage response plans must be developed for each
State where an entity owns or plans to own substations. The substation forced outage
response plan must be approved by the Applicable Authority. The substation forced
outage response plan should be updated monthly (??) and forwarded to the applicable
state authority within five (??) business days. Each substation forced outage response
plan should include the following components:
17 Comment [A35]: Owner Comment: This
document does not need this level of detail to define
forced outage.
Comment [A36]: Owner Comment: Too
frequent.
Comment [A37]: Owner Comment: Needs to
be more general or deleted.
Comments of the
MISO Transmission Owners

List of entity personnel assigned to provide emergency response to
substation forced outages including contact information of all assigned
personnel and at least two on-call employees that can immediately
respond. Contractors are not permitted to be used for forced outage
response for a substation.

The plan must list the location of the base of operations for emergency
response personnel and an explanation of how they will satisfy the
response time requirements.Personnel used for emergency response for
substation forced outages must be available on site to commence
substation troubleshooting or switching within 2 (??) hours. The plan
must list the location of the base of operations for emergency response
personnel and an explanation of how they will satisfy the response time
requirements if located more than 50 (??) miles from the substation.

The substation forced outage response plan should include procedures for
coordinating with the owners and operators of adjacent transmission
facilities to i) obtain clearance, ii) obtain headway and iii) obtain
information from recording devices from the owners of adjacent
transmission facilities that may be useful in troubleshooting (i.e., fault
recorder tapes, sequence-of-event recorders, annunciators and alarms,
SCADA recorded data, digital relay diagnostics, etc.). The entity is
expected to have procedures to maximize the use of information provided
by these recording devices and their own recording devices when
necessary to troubleshoot substation forced outages.

When the cause of the substation forced outage is determined, the entity
should initiate any necessary emergency testing and repairs in accordance
with the substation emergency testing and repairs qualifications outlined
in Section 4.4 unless a major storm/event (e.g., hurricane, etc.) for the
corresponding geographic area has been declared by MISO, in which case
emergency testing and repairs should be initiated as soon as practical
based on the relative priority of the substation forced outage with respect
to other forced outages in the area.

If no forced outage cause is found, the entity should have procedures
included in the substation forced outage response plan to place the
transmission facility back in service in a manner that minimizes risks to
personnel and public safety, equipment damage and adverse impacts to
18 Comments of the
MISO Transmission Owners
BES reliability. These procedures should be coordinated with other
transmission facility owners and MISO when appropriate.
4.3. Substation Switching
For a forced outage of a substation facility or Transmission Circuit terminated to the
substation, timely switching may be required to ensure reliability and to minimize the
duration of service interruptions to customers. Switching may also be necessary to assist
with an emergency condition at a neighboring substation or Transmission Circuit.
Furthermore, non-emergency switching is required to facilitate planned maintenance
outages and/or implementation of certain operating guides or similar procedures.
Entities that own transmission substations must develop a substation switching policy for
each State where they own or plan to own substations and these substation switching
policies must be approved by the Applicable Authority. Each substation switching
policy should be updated monthly (??) and forwarded to the Applicable Authority within
five (??) business days. The substation switching policy should include the following
components:

A minimum of oOne switching supervisor qualified individual employed
by the entity must be available assigned to each shift of the real-time
operations center and available on a 24/7 basis to write and issue
switching orders when required. The switching supervisor should be
qualified to write and issue transmission switching orders and issue
clearance and headway through a certified training program and must be a
NERC certified system operator. The switching supervisor must have
contact information to communicate with the owners of adjacent
Terminating Substations and Transmission Circuits that terminate at the
substation, must have available i) up-to-date detailed one-line diagrams for
the substation, ii) up-to-date relay functional diagrams for the substation,
iii) up-to-date relay panel drawings for the substation, iv) a map board
indicating the real-time status of switching devices at the substation,
Transmission Circuits that terminate at the substation (including Tapped
Substations if Type B Transmission Circuits) and adjacent Terminating
Substations and v) up-to-date switching diagrams for applicable
Transmission Circuits (including Tapped Substations) that terminate at the
substation and all adjacent Terminating Substations whether or not the
Transmission Circuits, Tapped Substations and/or adjacent Terminating
Substations are also owned by the entity. To ensure safety and reliability,
prior to issuing switching orders, the switching supervisor will coordinate
19 Comments of the
MISO Transmission Owners
as appropriate with switching supervisors employed by i) other
transmission owners that own and operate Type B Transmission Circuits
that terminate at the substation, ii) other transmission owners that own and
operate adjacent Terminating Substations and/or iii) load serving entities
that own and operate Tapped Substations connected to a Type B
Transmission Circuit that terminates at the substation in order to ensure
proper issuance of switching orders, clearance and headway. This
coordination will include updating each other when specific switching
orders have been completed.

List of entity personnel assigned to execute switching orders in substations
including contact information of all assigned personnel and at least two
on-call employees that can immediately respond. Substation switching
personnel should be qualified to execute transmission switching orders
and investigate annunciators, indicators and relay targets through a
certified training program. Contractors are not permitted to be used for
switching within substations.

The plan must list the location of the base of operations for emergency
response personnel and an explanation of how they will satisfy the
response time requirements.Personnel used for substation switching
should be available to commence substation switching within 2 (??) hours
of notification. The substation switching policy must list the location of
the base of operations for switching personnel and an explanation of how
the response time requirements will be satisfied if the base of operations is
located more than 25 (??) miles from the substation.

The switching policy should include procedures for non-emergency
switching to facilitate planned maintenance outages or restore service
following emergency repairs. These procedures should ensure
coordination between the entity switching supervisor and switching
supervisors employed by i) other transmission owners that own and
operate Transmission Circuits terminating at the substation, ii) other
transmission owners that own and operate adjacent Terminating
Substations and/or iii) load serving entities that own and operate Tapped
Substations connected to Type B Transmission Circuits that terminate at
the substation in order to ensure proper issuance of switching orders,
clearance and headway. This coordination should include i) coordination
of switching order issuance, ii) updates on switching completion and iii)
development of an overall switching strategy and sequence that takes into
20 Comment [A38]: Owner Comment: Should
match the requirements for line switching (4 hours).
Comment [A39]: Owner Comment: Too short.
Comments of the
MISO Transmission Owners
consideration both the switching device type (e.g., substation circuit
breaker with relays, air-break switch with vacuum interrupter attachments,
air-break switch with arcing horns, hook stick disconnects, etc.) and the
switching operation type (e.g., making or breaking parallel, interrupting
charging current, interrupting load when necessary, energizing a dead line,
etc.) to ensure the appropriate switching devices are used to perform the
appropriate switching tasks.

Any clearance or headway issued must be issued to an employee of the
entity even if the work is performed by a contractor. It will be the
responsibility of this employee to release clearance or headway when
he/she has verified conditions are acceptable for releasing clearance and/or
headway.
Comment [A40]: Owner Comment: This is
true for some Owners, but probably not all utilities.
4.4. Substation Emergency Testing and Repairs
Substation testing and repairs are often required following a major forced outage.
Emergency testing is required to diagnose equipment problems following a forced outage
or ensure equipment is in proper operating condition before returning it to service
following emergency repairs. Substation emergency repair includes fixing or replacing
one or more failed components within a substation and/or clearing a permanent shortcircuit fault from a substation bus or major equipment item. Substation emergency repair
is generally initiated as a result of a forced outage or a report from the public on an
abnormal or unsafe condition associated with a substation. An entity must develop a
substation emergency testing and repair policy for each State where they own substations.
Each substation emergency testing and repair policy must be approved by the Applicable
Authority. Each substation emergency testing and repair policy must be updated
annually (??) and forwarded to the Applicable Authority within ten (??) business days.
Each substation emergency testing and repair policy should include the following
components:

The plan must list the location of the base of operations for emergency
response personnel and an explanation of how they will satisfy the safety
response requirements.List of emergency testing performed on power
transformers following a forced outage and pass/fail criteria for returning
the transformer to service. Testing may be done by entity personnel or
qualified contractors. Contractors who perform substation testing must be
accredited by the InterNational Electrical Testing Association (NETA).
For tests performed after a forced outage, contractors should be available
on site with the necessary test equipment within 24 (??) hours of
21 Comment [A41]: Owner Comment: This is
very restrictive. What would be included in the
emergency testing and repair policy? This is
unnecessary oversight.
Comment [A42]: Owner Comment: Utility and
customer goal is minimal outage time, not a defined
time limit. A 24 hour time window is excessive.
Comments of the
MISO Transmission Owners
notification. At a minimum, an insulation power factor test and
transformer turns ratio test should be performed after a forced power
transformer outage before placing a transformer back in service.

List of emergency testing performed on circuit breakers after a forced
outage and pass/fail criteria for returning the circuit breaker to service.
Testing may be done by entity personnel or qualified contractors.
Contractors who perform substation testing must be accredited by NETA.
For tests performed after a forced outage, contractors should be available
on site with the necessary test equipment within 24 (??) hours of
notification. The entity should specify in the substation emergency testing
and repair policy which tests, if any, will be performed following a forced
outage and subsequent repairs for a circuit breaker mechanism failure,
circuit breaker interrupter failure and internal circuit breaker short-circuit
fault.
Comment [A43]: Owner Comment: Depends
on the type of breaker and history. Difficult to
include all criteria.

List of testing performed on protective relay schemes following the failure
of a protective relay scheme to operate properly including failures to trip,
false trips or overtripping. The substation emergency testing and repair
policy should include procedures and methods used to i) test batteries and
battery chargers, ii) test individual protective relays including verification
of programmed parameters and settings in digital relays, iii) test lockout
relays and auxiliary relays, iv) test instrument transformers, v) test
communications equipment and vi) perform functional and operational
tests of entire protective relay schemes including breaker tripping before
returning the relay scheme to service. Protective relay testing should be
done by qualified and specialized entity personnel only (i.e., engineers or
technicians employed by the entity that specialize in protective relay
systems).
Comment [A45]: Owner Comment: This
depends on the type of failure or fault. Not all of the
items need to be checked if a problem is found or a
protective device indicates a failure.

List of all other emergency substation tests performed by the entity
following a forced outage including test procedures and test methods.

List of entity personnel or contractors assigned to provide emergency
testing and/or repair services including contact information of all assigned
personnel and at least two on-call employees for each contractor.

If contractors are used for emergency testing and/or repair, the list of
contractors should include at least two contractors that can begin
emergency testing and/or repair work on the substation within 24 (??)
22 Comment [A44]: Owner Comment: There are
too many variations with the various types of
breakers installed.
Comments of the
MISO Transmission Owners
hours of notification. The substation emergency testing and repair policy
must list the locations of the base of operations for each of these
contractors and an explanation of how they will satisfy the response time
requirement if located more than 250 (??) miles from the substation.
Contractors performing emergency testing and repair should have ten (??)
years experience testing substation equipment and maintaining and
constructing substations.

If entity personnel are used for emergency testing and/or repair work,
personnel should be available to commence emergency testing and/or
repair work within 24 (??) hours of notification. The substation
emergency testing and repair policy must list the locations of the base of
operations for these emergency testing and repair personnel and an
explanation of how they will satisfy the response time requirement if
located more than 250 (??) miles from the substation.

When abnormal conditions are reported by the public, procedures should
be in place to have the condition inspected by an entity representative
(employee or contractor) within a reasonable amount of time (not more
than four (??) hours). When unsafe conditions are reported, the entity’s
real-time control center should initiate emergency response and personnel
should be on site within two (??) hours.

The substation emergency testing and repair policy should list the types of
tools and equipment needed for emergency testing and repair including
vehicles, heavy equipment, test equipment, live line tools, conventional
tools, rubber goods and other required tools and equipment. The policy
should state if this equipment is owned by the entity, the contractor or
another entity and the emergency procedures for obtaining the equipment
if not owned by the entity or contractors.
4.5. Substation Spare Parts and Equipment
The entity must identify itsmaintain sufficient spare parts and spare major equipment
items in inventory policy, including expected repair times. to make emergency repairs to
substations and substation equipment within a reasonable time frame. For purposes of
this qualification, spare parts will be classified as i) major equipment items, ii) major
equipment parts, iii) minor equipment items and iv) substation materials.
23 Comment [A46]: Owner Comment: This is
unnecessary.
Comments of the
MISO Transmission Owners
Major equipment items are large equipment items found in substations such as power
transformers, load tap changers, phase angle regulators, voltage regulators, circuit
breakers, switches and disconnects, series and shunt capacitor banks, series and shunt
reactor banks, static VAR compensators and DC converter equipment. For major
equipment items such as power transformers with a replacement lead time that exceeds
30 (??) days, a spare major equipment item must be maintained to protect against
catastrophic major equipment failure. For example, if a substation owned by an entity
contains a 448 MVA 345-138 kV three-phase autotransformer with a 13.2 kV delta
connected tertiary winding and an LTC, the entity would need to maintain a spare
transformer with comparable characteristics somewhere in the continental United States.
Spare major equipment items should be maintained such that they are available on-site
with a 30 (??) day notification. For equipment that consists of independent units for
each phase or pole (e.g., single-phase autotransformers, single-phase shunt reactors,
single-pole circuit breaker assemblies with independent mechanisms, etc.), it is only
necessary to maintain a spare for one phase or pole so long as steps are taken to prevent
the catastrophic failure of one unit from damaging an adjacent unit (e.g. sufficient
spacing, firewalls, etc.). If an on-site spare exists, it is not necessary to maintain an offsite spare so long as the on-site spare can be transported to any substation location
covered by the spare within 30 (??) days. For example, if an entity owns a substation
with a, 336 MVA, 230-161 kV bank of three 112 MVA single-phase autotransformers
and a fourth 112 MVA single-phase autotransformer is installed on site as an on-site
spare, no spare is required, and this on-site spare could also cover a 336 MVA, 230-161
kV bank of three single-phase autotransformers at another substation where an on-site
spare was not installed.
The only exception to this is if MISO determines that a specific facility is critical enough
to BES reliability to justify a dedicated on-site spare that would not be available to cover
facilities in other substations (e.g., 2,250 MVA 765-345 kV autotransformer bank with
on-site 750 MVA single-phase spare, etc.). It is also allowable to use a single spare to
cover power transformers with multiple ratings. For example, a 560 MVA 345-138 kV
three-phase auto transformer could serve as a spare for 560 MVA, 500 MVA, 448 MVA
and 336, MVA autotransformers as long as the other characteristics (e.g., voltages, tap
changers, etc.) were comparable.
In addition, for a given type of circuit breaker (where type is defined by nominal voltage,
continuous rating and interrupting rating), if an entity uses this type of circuit breaker
only in a double-breaker bus configuration, there is no requirement to maintain a spare
circuit breaker so long as each circuit breaker and the associated disconnect switches and
bus work have the same or higher rating as the corresponding transmission branch being
24 Comments of the
MISO Transmission Owners
protected. For example, if an entity owns two 765 kV substations that each terminate
two Transmission Circuits and one power transformer, and a double-breaker bus
configuration is used at both substations for 765 kV (total of twelve 765 kV circuit
breakers), then there is no requirement to maintain a spare 765 kV circuit breaker.
However, in this example, if this entity were to build a third 765 kV substation with a
three-breaker ring bus, a spare circuit breaker would then be required. The reason for
the double-breaker exemption is that an extended outage of one circuit breaker in a
double-breaker bus configuration would continue to be as reliable, or more reliable, than
a ring or straight bus with all circuit breakers in service. Finally, for major equipment
designated as spares, no cannibalization of parts should occur without prior approval of
MISO.
Major equipment parts include parts needed to repair major equipment items. Examples
of major equipment parts include, but are not limited to, bushings, pumps, fans, motors,
compressors, gaskets, contactors, trip coils, tripping springs, closing springs, temperature
gauges, pressure gauges, capacitor units, breaker mechanism parts and assemblies, main
breaker contact assemblies, breaker interrupter assembles, LTC mechanism parts,
terminal blocks and similar items. If a major equipment part is necessary for operation
of a major equipment item, the parts should be maintained in inventory by the entity at a
location where they can be available on site within 24 (??) hours. An example of this
type of major equipment part would be a power transformer bushing. If a major
equipment part is not required for operation of a major equipment item, the part must be
available within 10 (??) days, and does not need to be maintained in inventory by the
entity unless the lead time to obtain the part is greater than 10 (??) days including back
order. An example of this type of part would be a fan motor on a power transformer
with multiple cooling fans. For those major equipment parts that must be maintained in
inventory and available within 24 (??) hours, minimum inventory levels must be
established and documented to minimize the risk that a major equipment part is not
available when required. The entity must promptly reorder major equipment parts when
inventory levels are depleted below minimum requirements.
Comment [A48]: Owner Comment: Would
need to increase inventory and increase acceleration
of changeout if parts are no longer available.
Minor equipment items are smaller equipment items which include, but are not
necessarily limited to, protective relays, battery chargers, batteries, auxiliary relays,
lockout relays, motor operators, wave traps, surge arresters, instrument transformers,
station service transformers, panel meters, control switches, power line carrier
equipment, coupling capacitors and similar items. Minor equipment items should be
maintained in inventory by the entity at a location where they can be available on site
within 24 (??) hours. Minimum inventory levels must be established and documented to
minimize the risk a minor equipment item is not available when required. The entity
Comment [A49]: Owner Comment: This will
result in increased requirements for inventory.
25 Comment [A47]: Owner Comment: Too
restrictive.
Comments of the
MISO Transmission Owners
must promptly reorder minor equipment items when inventory levels are depleted below
minimum requirements.
Substation materials include all of the non-equipment materials necessary in a
substation. Examples of substation materials include, but are not limited to, rigid bus
conductor, strain bus conductor, grounding wire, control wire, conduit, conduit fittings,
connectors, insulators, attachment hardware, fasteners, pipe stands, dead-end structure
assemblies, bay assemblies, anchor bolts and similar items. Sufficient substation
materials should be maintained in inventory to make emergency repairs as needed unless
the material is widely and readily available elsewhere. For example, post insulators are
a specialty item that should be maintained in inventory whereas conduit and control wire
will likely be readily and widely available elsewhere. For those items maintained in
inventory, they should be maintained at a location where they can be available on site
within 24 (??) hours. Minimum inventory levels must be established and documented to
minimize the risk a substation material item is not available when required. The entity
must promptly reorder substation material items when inventory levels are depleted
below minimum requirements. For substation materials not maintained in inventory, the
entity should have 3 (??) local suppliers identified that can provide the materials on site
with 24 (??) hours notification, and arrangements should be made ahead of time for
emergency availability on weekends and holidays, otherwise the substation material
must be stocked by the entity.
The entity must develop a substation spare parts and equipment policy for each State
where they own substations. Each substation spare parts and equipment policy must list
minimum inventory levels, storage locations and emergency transportation arrangements
for major equipment parts, minor equipment items and substation materials. The policy
must also list local suppliers, including emergency contacts information, for substation
materials not maintained in inventory. For major equipment parts not maintained in
inventory, the policy must include information on suppliers and procedures for obtaining
parts within the required timeframe. When spare major equipment items must be
maintained, the policy should specify locations and transportation arrangements and
procedures. Each substation spare parts and equipment policy must be approved by the
Applicable Authority. The substation spare parts and equipment policy should be
updated quarterly (??) and a copy provided to the Applicable Authority within five (??)
business days.
With regard to planned maintenance outages, the entity should arrange to have all spare
parts, minor equipment items and substation materials on site prior to switching out any
portion of the transmission system to avoid a longer than required duration of the
26 Comment [A50]: Owner Comment: Too
restrictive.
Comment [A51]: Owner Comment: Over
regulated and requires more administration and
oversight.
Comments of the
MISO Transmission Owners
planned maintenance outage. This provision does not apply to defective parts
subsequently discovered during the planned maintenance outage.
4.6. Substation Preventative Maintenance Program
Substation preventative maintenance includes inspection and testing of substation
facilities on a routine schedule, identifying emergency or non-emergency maintenance
and repair requirements and scheduling maintenance and repair work to fix or replace
components as necessary to i) prevent a forced transmission outage, ii) prevent damage
or loss of life to equipment, iii) prevent unreasonable risk to reliability or service
interruptions to consumers and/or iv) correct an unsafe condition. The entity shall
develop a substation preventative maintenance plan for each State that must be approved
by the Applicable Authority. The substation preventative maintenance plan should be
updated annually (??) and a copy provided to the Applicable Authority within 10 (??)
business days. The substation preventative maintenance plan should outline i) specific
substation inspection cycles and methods, ii) on-line monitoring if used, iii) time-based
maintenance schedules when applicable, iv) duty based maintenance criteria when
applicable and v) condition-based maintenance criteria when applicable.
The substation preventative maintenance plan should include the following information:

Schedules and checklists for routine substation inspections and a
description of methods used (e.g., visual inspection, test operations, data
recording, infrared inspection, etc.). Routine substation inspection
frequencies for visual inspection and data recording should be no less
frequent than quarterly. General criteria used to trigger further testing,
non-emergency maintenance and repair or emergency maintenance and
repair should be outlined as well.

A description of any on-line monitoring in place for major equipment such
as power transformers and circuit breakers and how the data is analyzed
and used to make decisions regarding duty-based or condition-based
maintenance. For example, on-line I2T monitoring on circuit breakers and
the criteria for triggering duty-based circuit breaker maintenance or online oil monitoring on power transformers and the criteria for triggering
further testing or power transformer maintenance.

A list of major and minor equipment items and/or components of major
equipment items subject to time-based testing and maintenance including
a maintenance schedule and a list of testing and maintenance tasks
27 Comment [A52]: Owner Comment: Too
regulated and extra administration.
Comments of the
MISO Transmission Owners
typically performed. For example, certain protective relays and schemes
may be tested every three years.

A list of major and minor equipment items and/or components of major
equipment items subject to duty-based testing and maintenance including
the maintenance triggering criteria and a list of testing and maintenance
tasks typically performed. For example, certain circuit breaker operating
mechanisms may be maintained after so many circuit breaker operations.

A list of major and minor equipment items and/or components of major
equipment items subject to condition-based testing and maintenance
including methods for analyzing data, the maintenance triggering criteria
and a list of testing and maintenance tasks typically performed. For
example, a power transformer may be scheduled for a planned outage to
process or replace mineral oil as a result of annual oil sample tests or test
result trends over time.

Coordinated maintenance policies that reduce planned outage frequencies.
For example, the planned maintenance outage of a power transformer may
be coordinated so that it is scheduled at the same time as the routine
testing of the transformer’s differential relay scheme and the detailed
inspection of the high-side transformer circuit breaker mechanisms.

The preventative maintenance plan should include routine cycles for
insulation power factor testing, transformer turns ratio testing and oil
sample testing for power transformers. Routine oil sample testing for
preventative maintenance should be performed at least once per year, and
should include, at a minimum, dielectric strength, dissolved gas analysis,
moisture-in-oil, acid, color, interfacial tension and, if the power
transformer contains oil pumps, metal-in-oil tests. Testing may be done
by entity personnel or qualified contractors. Contractors who perform
substation testing must be accredited by NETA. On-line monitoring
equipment can be used in place of routine testing for preventative
maintenance, but tests should still be performed following a forced outage.

List of routine testing performed on circuit breakers including test cycles
for preventative maintenance and pass/fail criteria for tests. Testing may
be done by entity personnel or qualified contractors. Contractors who
perform substation testing must be accredited by NETA. The preventative
maintenance plan should include routine cycles for all applicable circuit
28 Comments of the
MISO Transmission Owners
breaker testing specified in the substation testing policy (e.g., insulation
power factor testing, time and travel analysis, contact resistance
measurements, etc.).

List of testing performed on protective relay schemes including test cycles
for preventative maintenance. The substation test policy should include
details on testing cycles, procedures and methods used to i) test batteries
and battery chargers, ii) test individual protective relays including
verification of programmed parameters and settings in digital relays, iii)
test lockout relays and auxiliary relays, iv) test instrument transformers, v)
test communications equipment and vi) perform functional and operational
tests of entire relay schemes including breaker tripping. Protective relay
testing should be done by qualified and specialized entity personnel only
(i.e., engineers or technicians employed by the entity that specialize in
protective relay systems).

List of all other routine substation tests performed by the entity as part of a
preventative maintenance program including test cycles, test procedures
and test methods.
The results of the preventive maintenance plan should be used to schedule and make
emergency and non-emergency repairs, including like-for-like capital replacements of
FERC retirement units to i) avoid forced outages, ii) prolong equipment life, iii) reduce
risk to BES reliability and adverse impacts to consumer reliability indices (e.g., SAIFI,
SAIDI, etc.) and iv) address unsafe operating conditions. Non-emergency repairs should
be scheduled within a reasonable timeframe, but not more than 60 (??) days from the
date of the inspection. Emergency repairs should be scheduled within 24 (??) hours or
as soon as practical thereafter.
4.7. Substation Modeling and Records
An entity must maintain models of all substations that can be used in power flow simulations,
dynamic simulations, production cost modeling simulations and short-circuit simulations.
These models must include load information for any loads supplied by the substations.
Model updates for power flow simulations, dynamic simulations and production cost
modeling simulations must be forwarded to MISO using the Model on Demand (MOD)
application. Model updates for short-circuit simulations, which include positive and zero
sequence models for facilities within the substation, should be submitted to MISO and the
entity responsible for performing short-circuit analysis in the area.
29 Comment [A53]: Owner Comment: Scheduled
outages on other parts of the system can impact
repairing in a timely manner.
Comments of the
MISO Transmission Owners
The entity must maintain as-built records for each substation facility and must update these
records when changes are made. The as-built records include, in addition to models, i) asbuilt one-line diagrams of all substation, ii) as-built relay functional diagrams, iii) as-built
general arrangement plans, iv) as-built site plans, v) as-built elementary diagrams for
protective relays, controls and metering and vi) as-built wiring diagrams for protective relays,
controls and metering. The as-built one-line diagram should be sufficient to write and issue
switching orders. The entity should retain the original detailed engineering documentation
for each substation for the life of the facility.
The entity must also maintain sufficient records to produce and maintain an accurate
Attachment O including information on plant and all applicable expenses. The entity should
maintain i) records on forced outages, ii) switching records, iii) emergency testing and repair
records and iv) preventative maintenance records regarding inspections, testing and
maintenance work for a period of ten (??) years. Testing results on major equipment should
be retained for the life of the equipment. Data recorded by SCADA or recorded manually
regarding equipment condition should also be maintained for the life of the equipment.
Other SCADA data should be retained for a period of three (??) years. The entity should
maintain up-to-date records on all spare parts inventory levels. The entity should retain
copies of the current and previously filed policies with the Applicable Authority.
30 Comment [A54]: Owner Comment: This is not
appropriate in a document of this type.
Comment [A55]: Owner Comment: None of
this seems like a qualification requirement. This
appears to be more appropriate for a business
practice/manual.