MidAmerican Energy Company
Reliability Planning Criteria for 100 kV and Above
March 1, 2016
Issued by: Dehn Stevens, Director
System Planning and Services
1.0
SCOPE
This document defines the criteria to be used in assessing the reliability of MidAmerican
Energy Company’s (MidAmerican’s) 100 kV and above system.
2.0
GENERAL
Reliability assessments of the MidAmerican 100 kV and above system are performed to
identify areas of the system where the reliability criteria are not expected to be met.
Reliability assessments are also performed to evaluate impacts of interconnections of new
generation, transmission, or loads on the MidAmerican 100 kV and above system1. In the
reliability assessments, contingencies are analyzed for reliability criteria violations
including overloads, low voltage, high voltage, transient instability, voltage instability
and cascading outages. In addition, circuit breaker interrupting capability, delivery point
reliability, voltage flicker, and harmonics are analyzed.
The MidAmerican 69 kV planning criteria augments this MidAmerican Energy Company
Reliability Planning Criteria for 100 kV and above. This means that, for 100 kV and
above outage events, the 69 kV system performance must be acceptable such that the 69
kV limits as provided in that 69 kV criteria are met on the 69 kV system. For example,
when a 161 kV line outage causes overloads and/or voltage violations on the 69 kV
system, a Corrective Action Plan must be developed that mitigates these overloads or
voltage violations on the 69 kV system.
3.0
PURPOSE
The purpose of these 100 kV and above reliability planning criteria, henceforth
“Criteria”, is to provide a basis for the development and operation of MidAmerican’s 100
kV and above2 system in the interest of its customers, communities served, and owners in
a consistent, reliable, and economic manner. It is intended that these Criteria are as
stringent or more stringent as the North American Electric Reliability Corporation
(NERC) Reliability Standards and the Midwest Reliability Organization (MRO)
Reliability Standards, as appropriate. Further, it is intended that these Criteria conform to
applicable rules and regulations of the Federal Energy Regulatory Commission (FERC)
and other regulatory bodies having jurisdiction.
These Criteria are subject to review and change at any time to conform to the MRO,
NERC and FERC criteria, rule and regulation changes in the future.
1
Reliability assessments of the MidAmerican 100 kV and above system are performed, as appropriate, for
interconnections to the MidAmerican system or neighboring systems. Also, the seams between MidAmerican and
neighboring systems are investigated for impacts of MidAmerican and neighboring-system contingencies.
2
For transformers, at least two windings must be connected at a voltage above 100 kV in order for the transformer to
be considered a part of the 100 kV and above system.
March 1, 2016
Page 2 of 28
4.0
SYSTEM PLANNING PERFORMANCE STANDARDS
A.
System Performance Criteria
The MidAmerican 100 kV and above system shall be planned, designed, and constructed
so that the network can be operated to supply projected customer demands and projected
firm transmission service at all demand levels over the range of forecast system demands,
under the contingency conditions defined in Table 1 (see Appendix for Table 1) without
exceeding stability limits, applicable thermal and voltage limits (see Table 2 in the
Appendix for steady-state voltage criteria), applicable limits to loss of demand or
curtailed firm transfer, and without resulting in cascading outages, uncontrolled
separation, or instability. The 100 kV and above system shall also be planned to include
sufficient Reactive Power resources to meet system performance criteria.
Planned system adjustments such as transmission configuration changes and redispatch of
generation are allowed if such adjustments are executable within the time duration
applicable to facility ratings. The controlled interruption of firm transmission service and
non-consequential load loss may be allowed to meet (1) Planning Events Category P2.4,
P4.6, P6, and P7 and all Extreme Events at 100 kV and above and (2) Planning Events
Category P2.2, P2.3, P4.1 through P4.5, P5, for 161 kV in Table 1(see Appendix for
Table 1). System readjustments are subject to the notes provided in Table 1, Section 5.0,
and other requirements of the NERC TPL and MRO Reliability Standards. The system
shall be planned, designed, and constructed to prevent subsynchronous resonance issues,
harmonic issues, voltage flicker issues, generator shaft torsional issues, and over dutied
fault interrupting device conditions. System assessments shall be conducted annually to
demonstrate that the system meets the latest Criteria and, as necessary, to evaluate
impacts of material changes in generation, transmission, or loads on the MidAmerican
100 kV and above system.
B.
Steady-State Voltage Criteria
The steady-state voltage provided to customers must comply with ANSI Standard C84.1
(see Reference C). This standard defines two voltage ranges within which the customer's
voltage must be maintained. Range A covers voltages for which the system is designed to
provide under normal conditions. The occurrence of service voltages outside this range
should be infrequent. Range B covers voltages outside of Range A that necessarily result
from practical design and operating conditions on supply or user systems, but which are to
be limited in extent, frequency, and duration. Corrective measures are to be taken within a
reasonable time to bring voltages back within Range A.
The devices and techniques used to maintain voltages within ranges A and B vary from
case to case. The voltages listed in Table 2 of the Appendix are those needed to provide
voltages to users within the required ranges and shall apply to the MidAmerican 100 kV
and above system. Note the major assumptions and considerations listed below the table.
March 1, 2016
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Reliability assessments of the MidAmerican 100 kV and above system shall include
evaluation of system voltages in a manner designed to:


C.
typically represent the minimum voltage conditions, for example, evaluation at
summer peak load. Cases are to be adjusted to reflect generation resource dispatch
that is expected to typically represent the voltage limit being evaluated and with
appropriate representation of the MW and MVAR loads including those of
generating stations, as appropriate.
typically represent the maximum voltage conditions, for example, using a spring
light load case with wind farms connected to the MidAmerican system operating
with no real power output, collector circuit MVAR charging represented, and with
the wind farm voltage control, if any, simulated.
Transient Voltage Criteria
Generator Bus Transient Voltage Limits shall adhere to the high voltage duration curve and
low voltage duration curve in Attachment 2 of NERC PRC-024.
Load Bus Transient Over Voltage Limits (the period after the disturbance has occurred but
not including the fault duration), maximum short-term AC voltage: 1.6 per unit voltage
from 0.01 to and including 0.04 seconds; 1.2 per unit voltage from 0.04 to and including
0.5 seconds; 1.1 per unit voltage from 0.5 to and including 5 seconds; and 1.05 per unit
voltage for greater than 5 seconds. These voltage limits also apply to buses without loads
and generators.
Load Bus Transient Low Voltage Recovery Limits are as follows: may be less than 0.7 per
unit voltage from 0 to 2 seconds after fault clearing. Voltage shall remain above 0.7 per
unit from 2 to 20 seconds after fault clearing. Voltage shall recover to 0.9 per unit 20
seconds after fault clearing.
The Load Bus Transient Over Voltage and Load Bus Transient Low Voltage Recovery
Limits are illustrated in Figure 1 below:
March 1, 2016
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Figure 1 Transient Voltage Limits
D. Voltage Stability
The MidAmerican 100 kV and above system shall be planned, designed and constructed to
provide sufficient reactive capacity and voltage control facilities at all demand levels and
committed Total Transfer Capability3 (as defined in the NERC Glossary) levels to satisfy
the reactive requirements and to ensure performance defined in Planning Events and
Extreme Events of Table 1. The system shall be planned so that there is sufficient margin
between the normal operating point and the collapse point for voltage stability to allow for
a reliable system.
Voltage stability studies shall be performed to demonstrate that there is sufficient margin
between the normal operating point and the collapse point. The studies shall include
voltage versus power transfer or system demand (P-V curve). Sufficient margin is
maintained by operating at or below Plimit. Plimit is determined by developing P-V curves for
3
See the definition at Glossary of Terms Used in NERC Reliability Standards.
March 1, 2016
Page 5 of 28
those buses that have the largest contribution to voltage instability due to the most limiting
disturbance as defined in Planning Event Category P1 in Table 1. Plimit is calculated as the
lesser of:



(0.9) * Pcrit where Pcrit is defined as the maximum power transfer or system
demand (nose of P-V curve) or
the maximum power transfer or system demand before a bus voltage falls
below 0.9 per unit (shown below in Figure 2 as point “a”), or
the Total Transfer Capability or system demand which does not result in a
post-contingency voltage violation.
Voltage
(pu)
1.0
0.9
0.8
Power Transfer (MW)
a
Pcrit
Figure 2 P-V Curve
E. System Frequency
Facilities must be planned to maintain system frequency between the thresholds plotted in
Figure 3, including a 10% reliability margin for both time and frequency, for all
contingency conditions defined in Table 1 in the Appendix. The overfrequency
thresholds plotted in Figure 3 reflect the most restrictive performance curve from either
PRC-006 or PRC-0244. The underfrequency thresholds plotted in Figure 3 reflect the
most restrictive performance curve from either PRC-024 or MidAmerican’s
underfrequency load shedding (UFLS) plan used to comply with PRC-006.
4
PRC-024-1 becomes enforceable on 7/1/2016.
March 1, 2016
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MidAmerican’s UFLS plan must not be designed to initiate the tripping of load if system
frequency is between the thresholds plotted in Figure 3. Furthermore, generators
interconnected to the MidAmerican transmission system must be designed to remain
connected to the system if system frequency is between the thresholds plotted in Figure 3.
Therefore, by maintaining system frequency between the thresholds plotted in Figure 3,
facilities are planned in such a manner to avoid non-consequential loss of load, as
required by footnote 12 to Table 1 in TPL-001-4, and unintended generation tripping.
Figure 3: Planning Thresholds for System Frequency
0.1
0.1 0.33
0.33
4.0
4.0
30.0
30.0
10 .
6. 1090.935 1.4573 60.7 1.
2.
3.
4.
5.
90.935 1.4573 60.5
7. 10
1.7373 59.3
8. 10
9.
10
.
March 1, 2016
.
1090.935
1.4573 60.5
1.7373 59.3
100.116
.
.
10
1.7373 59.5
10
.
1.
2.
3.
4.
5.
6.
100.116
100.116
58
59 59.3 59.3 59.3 59.3 7. 59.3
8.
log10
1.7373
Page 7 of 28
62.21
.
.
100.116
9. 59.5
61.8
61.8
61.8
0.686 log
60.7
60.5
60.5
60.5
F.
Disturbance Performance Requirements
The MidAmerican 100 kV and above system shall be planned, designed and constructed to
meet the disturbance performance requirements set forth in Table 1 in the Appendix as
modified by the MEC Note 3 which provides the definition for Cascading, MEC Note 4
which states that Angular Transient Stability Minimum Damping Ratio (ζ) not to be less
than 0.03, and MEC Note 5 where a one-cycle safety margin must be added to the actual or
planned fault clearing time.
5.0
MITIGATION ALTERNATIVES TO MEET RELIABILITY CRITERIA
When system simulations indicate an inability of the 100 kV and above system to meet the
performance requirements of Table 1, the deficiencies must be resolved by a mitigation plan.
Below is a summary of the available mitigation alternatives for each contingency category of
Table 1. This section is intended on being consistent or more stringent than Table 1.
A. NERC Planning Event Category P0 criteria violations
Facility loadings exceeding facility normal ratings as provided in Reference D or bus
voltages lower than the “Normal Minimum Voltage” and higher than the “Maximum
Voltage” as defined in Table 2 require physical upgrades to meet system performance
requirements under NERC Category P0 conditions.
B. NERC Planning Events (excluding P3 and P6) criteria violations
NERC Planning Events (excluding P3 and P6) contingencies at peak, shoulder, off-peak,
and light load conditions resulting in facility loading above emergency ratings, bus
voltages below “After First Contingency Minimum Voltage” as defined in Table 2, or bus
voltages above the “Maximum Voltage” as defined in Table 2, require physical upgrades
to meet system performance requirements. Manual readjustment during and after the
contingency cannot be used to resolve the NERC Planning Events (excluding P3 and P6)
criteria violations.
NERC Planning Events (excluding P3 and P6) contingencies at peak, shoulder, off-peak,
and light load conditions resulting in facility loading between normal and emergency
ratings as provide in Reference D or causing bus voltages between the “Normal
Minimum Voltage” and the “After First Contingency Minimum Voltage” as defined in
Table 2 may rely on manual adjustment in an operating guide, subject to the requirements
in Section 5.0 E. and F., to return the facility loading to the facility normal rating and bus
voltages to between the “Normal Minimum Voltage” and the “Maximum Voltage”. This
is provided the readjustments do not result in load shedding, do not cause additional
thermal or voltage violations, and meet the requirements of Section 5.0 E. and F. If
manual readjustment is not capable of implementation within the applicable facility
emergency rating duration or the applicable voltage readjustment period as identified in
footnote 4 of Table 2, a physical upgrade is required.
March 1, 2016
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C. Maintenance Outages (Planning Events P3a and P6a in Table 1).
At shoulder and light load conditions, a maintenance outage of NERC Planning Event
Category P1 followed by system readjustment followed by a single initiating event
consisting of the loss of one of the following:
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Transmission Circuit
Transformer
Shunt Device
Single pole of a DC line
Opening of a line section w/o a fault
Bus Section Fault
Internal Breaker Fault (non-Bus-tie Breaker)
Internal Breaker Fault (Bus-tie Breaker)
Any two adjacent (vertically or horizontally) circuits on common structure
Loss of a bipolar DC line
resulting in facility loadings above emergency ratings, bus voltages below the “After
First Contingency Minimum Voltage” as defined in Table 2 or bus voltages above the
“After First Contingency Maximum Voltage” as defined in Table 2, a physical upgrade
will be required. Manual readjustment after the outage combination is not an acceptable
mitigating solution.
At shoulder and light load conditions, a maintenance outage of NERC Planning Event
Category P1 followed by system readjustment followed by a single initiating event
consisting of the loss of one of the following:
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Transmission Circuit
Transformer
Shunt Device
Single pole of a DC line
Opening of a line section w/o a fault
Bus Section Fault
Internal Breaker Fault (non-Bus-tie Breaker)
Internal Breaker Fault (Bus-tie Breaker)
Any two adjacent (vertically or horizontally) circuits on common structure
Loss of a bipolar DC line
resulting in facility loadings between the normal rating and the emergency rating and bus
voltages between the “Normal Minimum Voltage” and the “Maximum Voltage” as
defined in Table 2 may rely on manual adjustment in an operating guide, subject to the
requirements in Section 5.0 E. and F. If manual readjustment cannot be implemented
within the applicable facility emergency rating duration or the applicable voltage
readjustment period as identified in footnote 4 of Table 2, a physical upgrade is required.
March 1, 2016
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D. NERC Planning Event Category P3 and P6 (N-1-1) criteria violations
An operating guide with manual readjustment may be used after the first contingency of
NERC Planning Event Category P3 and P6 (N-1-1) event to prevent reliability criteria
violations following the second contingency of an N-1-1 event. The operating guide used
between the first and second contingency must keep facility loadings after the second
contingency of an N-1-1 event below their emergency ratings and bus voltages after the
second contingency of an N-1-1 event between “After Second Contingency Voltage” and
“Maximum Voltage” as defined in Table 2.
An operating guide with manual readjustment may also be used after the second
contingency of NERC Planning Event Category P3 and P6 contingencies, if the second
contingency of the event results in:
o facility loadings between normal and emergency ratings
o bus voltages between “Normal Minimum Voltage” and the “After Second.
Contingency Voltage” as defined in Table 2, or
o bus voltages between the “Normal Minimum Voltage” and the “Maximum
Voltage” as defined in Table 2.
However, any such operating guide is subject to the requirements in Section 5.0 E. and
F., and must return facility loadings to the facility normal ratings and bus voltages
between the “After 1st Contingency Minimum Voltage” and the “Maximum Voltage”.
Such operating guides must be able to return facility loadings and bus voltages to
acceptable levels within the applicable facility emergency rating duration or the
applicable voltage readjustment period as identified in footnote 4 of Table 2.

SOL Limitation
If analysis shows after the second contingency of an N-1-1 event, facility loadings
exceed one or more System Operating Limits (SOLs), as defined in Appendix L of the
Midcontinent Independent System Operator’s (MISO’s) BPM-020 Transmission
Planning Business Practice Manual, then the allowable readjustment period between
the first and second contingency is no more than 2 hours.
After the second contingency of the P3 or P6 Planning Event, the allowable system
readjustment period is no more than the applicable emergency rating duration for
thermal constraints, and up to 1 hour for voltage constraints.

IROL Limitation
If analysis shows that after the second contingency of an N-1-1 event, facility loadings
exceed one or more Interconnected Reliability Operating Limits (IROLs) as defined in
Appendix L of Midcontinent Independent System Operator’s (MISO’s) BPM-020
Transmission Planning Business Practice Manual, then the allowable readjustment
period between the first and second contingency is no more than 30 minutes.
March 1, 2016
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After the second contingency of the NERC Planning Event P3 or P6, the allowable
system readjustment period is no more than the applicable emergency rating duration
for thermal constraints, and up to 1 hour for voltage constraints.

Maximum Loading Limitation
Manual system readjustments cannot be used after the first contingency of an N-1-1
event (P3 and P6) to prepare for the second contingency, if analysis shows that after the
second contingency, without manual system readjustments:
o either facility loadings are at 125% or more of the emergency thermal rating, or
o system voltages are at 0.80 per unit or below.
A physical upgrade is required for a NERC Planning Event P3 and P6 (N-1-1) if an
operating guide cannot be used in accordance with the appropriate provision or provisions
of Section 5.0 D, 5.0 E, or 5.0 F.
E. General Requirements of Operating Guides
An operating guide, when available as a mitigation solution, may include generation
redispatch (according to the requirements of Section 5.0 E. and F.), capacitor and reactor
switching including those switched by automated controls, LTCs including those with
automatic controls or under operator control, controlled HVDC power flow, and/or other
system reconfiguration (such as transmission and transformer tripping or switching)
assuming that such reconfiguration does not result in load shedding and does not cause
additional thermal or voltage violations.
In situations where there is a firm commitment to proceed with a physical upgrade to
mitigate the criteria violation and a temporary operating guide is needed as a bridge, the
following unusual measures will be allowed:
 a temporary short-time duration emergency limit provided the limit is consistent
with the time required to complete the necessary operating steps to return to
normal time duration limits,
 a temporary operating configuration (i.e. operating a ring-bus breaker as normally
open) assuming that the temporary operating configuration can be reasonably
accommodated and does not cause load shedding, violation of thermal ratings or
bus voltages, or significant operational issues, or
 as a last resort, the temporary operating guide may include controlled load
shedding provided the load shedding is consistent with the latest versions of the
NERC TPL standards5. Last resort means that no temporary measure other than
non-consequential load dropping can be taken to mitigate violations until a more
permanent Corrective Action Plan can be adopted. For example, if facilities are
being considered for retirement that cause the violations then such retirement
5
It should be noted that footnote 12 of the NERC TPL-001-4 reliability standard provides specific limitations to nonconsequential load dropping for certain outage events. See Attachment 1 in the Appendix.
March 1, 2016
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must be delayed until a Corrective Action Plan such as an operating guide that
does not require non-consequential load dropping is adopted or a system
improvement is completed and put in-service.
Approved operating guides will be re-evaluated on a regular basis to confirm the
continued ability to meet the performance requirements of Tables 1 and 2 through
implementation of the operating guide. This includes a requirement that additional
thermal or voltage violations not be created through implementation of the operating
guide.
F. Generation Redispatch Limitations
The following criteria shall be met to consider a generation redispatch as a viable
mitigation alternative:

Due to the uncertainty that any existing generating unit will continue to be a viable
unit over the planning horizon, a redispatch mitigation alternative must demonstrate
that there are sufficient generating units that are available to provide the incremental
capacity necessary to maintain loadings and voltages within applicable ratings,
without reliance on any single unit. In general, all Network Resources (NRs) and
Energy Resources (ERs) are candidates for redispatch as their output can be reduced
to minimum levels or turned off, including wind plants. If generating units are to be
decommitted, the reliability impacts of the generation change, including a voltage
analysis, would need to be evaluated.

The participating generators must have a distribution factor of greater than 3%.
Distribution factor is defined as the sensitivity of the generating unit to the thermal
constraint resulting from the P3 or P6 contingent event. Lower than 3% distribution
factor is indicative of an inefficient redispatch.

No more than 10 individual conventional units or individual wind plants shall be used
in any redispatch scenario.

No more than 1,000 MW shall be used to increment and no more than 1,000 MW
shall be used to decrement in any redispatch scenario. Therefore, no more than a total
amount of 2,000 MW of generation shift shall be allowed to redispatch around a
constraint.

Non dispatchable units will be excluded from redispatch calculations. Nuclear
generating units will also be excluded unless otherwise required by their operating
agreements. In general, feedback from other MISO market participants will be
requested regarding the reasonableness of units to be considered in the redispatch
options prior to commencement of annual reliability assessments.
March 1, 2016
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
After redispatch the loadings on all facilities must be at or within applicable ratings
per MidAmerican’s facility rating methodology consistent with NERC FAC-008
standard.

Consideration of external (non-MISO) generation in redispatch calculations:
o If the identified P3 or P6 driven constraint is a PJM-MISO reciprocal
coordinated flowgate (RCF) eligible for market to market redispatch, PJM
units, respectively, will be included in the redispatch.
o If the identified P3 or P6 driven constraint is not currently a PJM-MISO
reciprocal coordinated flowgate (RCF), the flowgate will be recommended
for RCF qualification study. If not eligible, PJM units will not be included
in the redispatch.
o Generators considered within existing operating guides, procedures and
Special Protection Schemes (SPS) will be included as applicable to the
overloaded facilities.
o No other non-MISO units along seams will be used in redispatch.
G. Remedial Action Schemes
A Remedial Action Scheme (RAS) may be considered to address transmission issues
when there is a transmission infrastructure weakness that may lead to cascading events,
system collapse or large loss of load and where, in MidAmerican’s sole judgment,
improvements to resolve the transmission infrastructure weakness are not practical. An
example of such a case is an HVDC line which is designed to transmit large amounts of
power for long distances that could cause cascading events, system collapse or large loss
of load as a result of single pole block or double pole block that MidAmerican determines
cannot reasonably provide sufficient capacity on the HVDC line or other transmission
facilities to completely eliminate the need for an RAS.
In situations when other transmission improvements are considered practical, an RAS
will be allowed only on a temporary basis so that planned transmission improvements can
be completed. The transmission improvements will need to be placed into the MISO
Transmission Expansion Plan process. A scope and schedule for the planned transmission
improvements will need to be approved by MidAmerican prior to the installation of the
RAS. A termination date for the RAS will be set consistent with the schedule of the
planned transmission improvements.
For the application of RASs, the following will apply:

The system must operate within the applicable NERC, MRO, and MidAmerican
reliability criteria at all times. This includes prior to, during, and after the
operation of the RAS.

The controls used to sense the system conditions of concern and to trip the facility
must meet all the criteria and guidelines of NERC, MRO and MidAmerican for an
RAS including dual redundancy of all components of the RAS and the ability to
March 1, 2016
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stay within all applicable reliability criteria with the failure of a component of the
RAS. Testing of the RAS and documentation of the testing is also required.

The RAS must not trip facilities that interconnect to the transmission system at
different substations or switching stations. The RAS may trip facilities that are
physically located at different points on the electric system provided that
ultimately they all interconnect to the transmission system at the same location.

If an RAS already exists for the event identified as requiring an RAS to meet
NERC compliance, a new RAS cannot be added to trip additional facilities at the
existing location or another location.

MidAmerican retains the right to determine whether or not an interconnecting
party will own and operate the RAS.
The existing RAS at the Tiffin Substation is a grandfathered RAS that is not subject to
the requirements of this section.
6.0
SHORT CIRCUIT CRITERIA
When the short circuit analysis portion of the 100 kV and above reliability assessment is
conducted, the analysis shall be used to determine whether circuit breakers have
interrupting capability for faults that they will be expected to interrupt using the system
short circuit model with any planned generation and transmission facilities in service
which could impact the study area.
Short circuit currents are evaluated in accordance with industry standards as specified in
American National Standards report ANSI C37.5 for breakers rated on the total current
(asymmetrical) basis and IEEE Standard report C37.010 for breakers rated on a
symmetrical current basis.
In general, fault current levels must be within specified momentary and/or interrupting
ratings of circuit breakers for studies made with all facilities in service, and with
generators and synchronous motors represented by their appropriate (usually subtransient saturated) reactances. For any circuit breaker which is shown to have a shortcircuit duty that exceeds its interrupting ratings, Corrective Action Plans will be developed.
Corrective action plans may include breaker replacement, system reconfiguration or
operating guides.
7.0
VOLTAGE FLICKER CRITERIA
Figure 4 provides MidAmerican’s allowable fluctuations in supply voltage which is based
upon industry guidelines and standards.
MidAmerican utilizes the International
Electrotechnical Commission (IEC) method in setting allowable voltage flicker levels for
the MidAmerican system taking into account all flicker causing sources. The allowable
voltage flicker limit for an individual customer is set to 3% for intact system conditions.
March 1, 2016
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For new projects, the allowable voltage flicker limit is set to 5% for single 69 kV and above
element outage conditions. Arc furnaces must demonstrate through rigorous EMTP
calculations or equivalent and the MidAmerican performance requirements that voltage
flicker levels will be acceptable to MidAmerican customers. Figure 4, as well as, industry
information on arc furnaces will be considered in determining acceptable voltage flicker
levels on a case by case basis for arc furnaces.
Figure 4 Allowable Voltage Flicker Curves
(Solid Line-System Intact & Dashed Line-Outage Conditions)
8.0
HARMONIC DISTORTION LEVEL CRITERIA
MidAmerican’s harmonic distortion level criteria as provided in Tables 3 through 5 are
intended to provide for allowable harmonic injection from individual customers so as not to
degrade the performance of the equipment of other customers, cause abnormal heating in
the MidAmerican’s facilities, cause metering errors, or cause objectionable interference in
communication facilities. Harmonic levels shall be monitored at customer locations where
harmonic levels have or may exceed specified limits.
MidAmerican’s allowable harmonic limits are those of IEEE 519- IEEE Recommended
Practices and Requirements for Harmonic Control in Electrical Power Systems.
MidAmerican’s harmonic distortion limits focus on harmonics at either the point of
common coupling (PCC), which is the point between the customer that is the harmonics
source and other customers, the point of metering, or the point of interference (POI). The
POI is a point that both MidAmerican and the customer can either access for direct
measurement of the harmonic indices meaningful to both or estimate the harmonic indices
through mutually agreed upon methods. The MidAmerican criteria is designed with the
goal of reducing the harmonic effects at any point in the entire system by establishing
March 1, 2016
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limits on certain harmonic indices (currents and voltages) at either the PCC, a point of
metering or a POI.
Nominal Voltage
Individual Voltage
Distortion (%)
Total Voltage
Distortion THD (%)
69.001 kV to 161 kV
1.5
2.5
161.001 kV and above
1.0
1.5
Table 3 Voltage Distortion Limits6,7
Maximum Harmonic Current Distortion in Percent of IL
Individual Harmonic Order (Odd Harmonics)
Isc/IL
<11
11<h<17
17<h<23
23<h<35
h>35
TDD
<208
2.00
1.00
0.75
0.30
0.15
2.50
20<x<50
3.50
1.75
1.25
0.50
0.25
4.00
50<x<100
5.00
2.25
2.00
0.75
0.35
6.00
100<x<1000
6.00
2.75
2.50
1.00
0.50
7.50
>1000
7.50
3.50
3.00
1.25
0.70
10.00
Table 4 - Current Distortion Limits for Systems 69.001 kV through 161 kV9,10,11
6
Table 1, IEEE 519-2014, IEEE Recommended Practices and Requirements for Harmonic Control in Electrical Power
Systems, page 6.
7
High-voltage systems can have up to 2.0% THD where the cause is an HVDC terminal that will attenuate by the time
it is tapped for a user.
8
All power generation equipment is limited to these values regardless of actual Isc/IL.
9
Table 3, IEEE 519-2014, page 8.
10
Even harmonics are limited to 25 % of the odd harmonic limits in the tables. Current distortions that result in a direct
current offset, e.g. half wave converters, are not allowed.
11
h = order of harmonic; Isc = maximum short-circuit current at either the PCC, the metering point, or the POI; IL =
maximum demand load current (fundamental frequency component) at either the PCC, the metering point or the POI;
TDD = the total root-sum-square harmonic current distortion, in percent of the maximum demand load current (15 or
30 min demand) at the PCC, the metering point, or the POI.
March 1, 2016
Page 16 of 28
Maximum Harmonic Current Distortion in Percent of IL Individual Harmonic Order (Odd
Harmonics)
Isc/IL
<11
11<h<17
17<h<23
23<h<35
35<h<50
TDD
<25
1.00
0.50
0.38
0.15
0.10
1.50
25<50
0
>50
2.00
1.00
0.75
0.30
0.15
2.50
3.00
1.50
1.15
0.45
0.22
3.75
Table 5 - Current Distortion Limits for High Voltage Systems (>161 kV) and Dispersed
Generation and Cogeneration12,13
9.0
100 KV AND ABOVE FACILITY RATING METHODOLOGY
MidAmerican’s 100 kV and Above Facility Ratings Methodology shall be used to establish
and communicate MidAmerican’s facility ratings for the 100 kV and above system.
10.0
DOCUMENT CONFLICTS
If there are conflicts in this document, the more stringent provision takes priority.
11.0
CONCLUSIONS
This document presents the criteria for planning the MidAmerican 100 kV and above
system. The purpose of these criteria is to provide a basis for system simulations and
associated assessments needed periodically to ensure that reliable systems are developed in
time to meet specified performance requirements, and continue to be modified or upgraded
as necessary to meet present and future system needs.
12
Table 4, IEEE 519-2014, page 9.
Even harmonics are limited to 25 % of the odd harmonic limits in the tables. Current distortions that result in a direct
current offset, e.g. half wave converters, are not allowed.
13
March 1, 2016
Page 17 of 28
12.0
REFERENCES (USE LATEST REVISION)
A.
B.
C.
D.
E.
F.
G.
H.
I.
J.
March 1, 2016
American National Standards Institute (ANSI) C37.010—Application Guide for
AC High-Voltage Circuit Breakers Rated on a Symmetrical Current Basis
ANSI C37.5—Guide for Calculation of Fault Currents for Application of AC HighVoltage Circuit Breakers Rated on a Total Current Basis
ANSI Standard C84.1—Electric Power Systems and Equipment-Voltage Ratings
MidAmerican Energy Company 100 kV and Above Facility Ratings Methodology
NERC Glossary of Terms
Electric Utility Engineering Reference Book, Volume 3, pg. 347, ABB Power
Systems Inc., February 1989.
IEEE 519 – IEEE Recommended Practices and requirements for Harmonic Control
in Electrical Power Systems.
International Electrotechnical Commission (IEC), “IEC 1000 Electromagnetic
compatibility (EMC) – Part 3: Limits – Section VII: Limitation of voltage
fluctuations and flicker for equipment connected to medium and high voltage
power supply systems – technical report type II”, Project number 1000-3-7
IEC, “Disturbances in supply systems caused by household appliances and similar
electrical equipment, Part 3: Voltage fluctuations”, Publication 555-3
NERC TPL-001-4 - Transmission System Planning Performance Requirements.
Page 18 of 28
Appendix
Table 1 – Steady State & Stability Performance Planning Events
Steady State & Stability:
a.
b.
c.
d.
The System shall remain stable. Cascading and uncontrolled islanding shall not occur. MEC Note 3
Consequential Load Loss as well as generation loss is acceptable as a consequence of any event excluding P0.
Simulate the removal of all elements that Protection Systems and other controls are expected to automatically disconnect for each event.
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.
g.
h.
i.
Applicable Facility Ratings shall not be exceeded. MEC Note 1
System steady state voltages and post-Contingency voltage deviations shall be within acceptable limits as established by the Planning Coordinator and
the Transmission Planner.
Planning event P0 is applicable to steady state only.
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
P0
No
Contingency
P1
Single
Contingency
P2
Single
Contingency
Fault
Type 2
BES Level
3
Interruption of
Firm Transmission
Service Allowed 4
Non-Consequential
Load Loss Allowed
None
N/A
EHV, HV
No
No
Loss of one of the following:
1. Generator
2. Transmission Circuit
3. Transformer 5
6
4. Shunt Device
3Ø
EHV, HV
No
9
No12
5. Single Pole of a DC line
SLG
1. Opening of a line section w/o
a fault 7
N/A
EHV, HV
No9
No12
EHV
No
No
2. Bus Section Fault
SLG
HV
Yes
Yes
EHV
No
No
HV
Yes
Yes
EHV, HV
Yes
Yes
Event 1, MEC Note 2
Initial Condition
Normal System
Normal System
Normal System
3. Internal Breaker Fault 8
(non-Bus-tie Breaker)
SLG
4. Internal Breaker Fault (Bus-tie
8
Breaker)
SLG
9
9
Category
P3
Multiple
Contingency
Initial Condition
Loss of generator unit
followed by System
9
adjustments
Event 1, MEC Note 2
Loss of one of the following:
1. Generator
2. Transmission Circuit
5
3. Transformer
4. Shunt Device 6
5. Single pole of a DC line
P3a
Multiple
Contingency
Maintenance
Outage
P4
Multiple
Contingency
(Fault plus
stuck
breaker10)
March 1, 2016
Loss of generator unit at
load levels at which
maintenance outages are
typically taken, such as
shoulder and light load
conditions followed by
System adjustements9
Normal System
Loss of one of the following:
1. Generator
2. Transmission Circuit
5
3. Transformer
4. Shunt Device 6
5. Single pole of a DC line
6. Opening of a line section w/o
7
a fault
7. Bus Section Fault
8. Internal Breaker Fault 8
(non-Bus-tie Breaker)
9. Internal Breaker Fault (Bus-tie
8
Breaker)
10. Any two adjacent (vertically
or horizontally) circuits on
common structure 11
11. Loss of a bipolar DC line
Loss of multiple elements caused
by a stuck breaker 10(non-Bus-tie
Breaker) attempting to clear a
Fault on one of the following:
1. Generator
2. Transmission Circuit
5
3. Transformer
6
4. Shunt Device
5. Bus Section
6. Loss of multiple elements
10
caused by a stuck breaker
(Bus-tie Breaker) attempting
to clear a Fault on the
associated bus
Page 20 of 28
Fault
Type 2
3
Interruption of
Firm Transmission
Service Allowed 4
EHV, HV
No
9
No12
EHV, HV
No9
No12
EHV
No9
No
HV
Yes
Yes
EHV, HV
Yes
Yes
BES Level
Non-Consequential
Load Loss Allowed
3Ø
SLG
3Ø
SLG
SLG
SLG
Category
Initial Condition
Event 1, MEC Note 2
Delayed Fault Clearing due to the
13
failure of a non-redundant relay
protecting the Faulted element to
operate as designed, for one of
the following:
1. Generator
2. Transmission Circuit
3. Transformer 5
6
4. Shunt Device
5. Bus Section
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. Transformer 5
6
3. Shunt Device
4. Single pole of a DC
line
P6a
Multiple
Contingency
Maintenance
Outage
(Two
overlapping
singles)
Loss of one of the
following at load levels at
which maintenance
outages are typically
taken, such as shoulder
and light load conditions
followed by System
adjustments.9
1. Transmission Circuit
2. Transformer 5
3. Shunt Device6
4. Single pole of a DC
line
Loss of one of the following:
1. Transmission Circuit
2. Transformer 5
3. Shunt Device 6
4. Single pole of a DC line
5. Opening of a line section w/o
a fault 7
6. Bus Section Fault
7. Internal Breaker Fault 8
(non-Bus-tie Breaker)
8. Internal Breaker Fault (Bus-tie
Breaker) 8
9. Any two adjacent (vertically or
horizontally) circuits on common
structure 11
10. Loss of a bipolar DC line
Normal System
The loss of:
1. Any two adjacent (vertically or
horizontally) circuits on
common structure 11
2. Loss of a bipolar DC line
P7
Multiple
Contingency
(Common
Structure)
March 1, 2016
Loss of one of the following:
1. Transmission Circuit
2. Transformer 5
3. Shunt Device 6
4. Single pole of a DC line
Page 21 of 28
3
Interruption of
Firm Transmission
4
Service Allowed
Non-Consequential
Load Loss Allowed
EHV
No9
No
HV
Yes
Yes
3Ø
EHV, HV
Yes
Yes
SLG
EHV, HV
Yes
Yes
3Ø
EHV, HV
No
Yes
SLG
EHV, HV
No
Yes
SLG
EHV, HV
Yes
Yes
Fault
Type 2
BES Level
SLG
Table 1 – Steady State & Stability Performance Extreme Events
Steady State & Stability
For all extreme events evaluated MEC Notes 2 and 4:
a. Simulate the removal of all elements that Protection Systems and automatic controls are expected to disconnect for each Contingency.
MEC Note 5
b. Simulate Normal Clearing unless otherwise specified.
Steady State
1. Loss of a single generator, Transmission Circuit, single pole of a DC
Line, shunt device, or transformer forced out of service followed by
another single generator, Transmission Circuit, single pole of a
different DC Line, shunt device, or transformer forced out of service
prior to System adjustments.
2. Local area events affecting the Transmission System such as:
a. Loss of a tower line with three or more circuits.11
b. Loss of all Transmission lines on a common Right-of-Way11.
c. Loss of a switching station or substation (loss of one voltage
level plus transformers).
d. Loss of all generating units at a generating station.
e. Loss of a large Load or major Load center.
3. Wide area events affecting the Transmission System based on
System topology such as:
a. Loss of two generating stations resulting from conditions
such as:
i. Loss of a large gas pipeline into a region or
multiple regions that have significant gas-fired
generation.
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.
March 1, 2016
Page 22 of 28
Stability
1. With an initial condition of a single generator, Transmission circuit,
single pole of a DC line, shunt device, or transformer forced out of
service, apply a 3Ø fault on another single generator, Transmission
circuit, single pole of a different DC line, shunt device, or transformer
prior to System adjustments.
2. Local or wide area events affecting the Transmission System such as:
10
13
a. 3Ø fault on generator with stuck breaker or a relay failure
resulting in Delayed Fault Clearing.
10
b. 3Ø fault on Transmission circuit with stuck breaker or a relay
13
failure resulting in Delayed Fault Clearing.
c. 3Ø fault on transformer with stuck breaker10 or a relay failure13
resulting in Delayed Fault Clearing.
d. 3Ø fault on bus section with stuck breaker10 or a relay failure13
resulting in Delayed Fault Clearing.
e. 3Ø internal breaker fault.
f.
Other events based upon operating experience, such as
consideration of initiating events that experience suggests
may result in wide area disturbances
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 Non-Consequential 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.
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).
March 1, 2016
Page 23 of 28
Table 1 – Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)
MEC Notes:
1.
2.
3.
4.
5.
March 1, 2016
Applicable rating refers to the applicable normal and emergency facility thermal rating or system voltage limit as determined and consistently applied by
the system or facility owner. Applicable ratings may include emergency ratings applicable for short durations as required to permit operating steps
necessary to maintain system control. All ratings must be established consistent with applicable NERC Planning Standards addressing facility ratings.
MidAmerican’s ratings are provided in Reference D and voltage limits in Table 2 of the Appendix.
Only those Planning Events and Extreme Events that are expected to produce more severe System Impacts on the BES must be identified and
evaluated for system performance.
Cascading in steady state analysis is based, in part, upon the MISO default and is as follows:
a. Four or more elements trip due to excessive loading, power swings, or abnormal system voltages in planning simulations where tripping is not due
to primary or backup protection to clear faults or due to the expected operation of an SPS.
b. One or more elements trip due to excessive loading, power swings, or abnormal system voltages where tripping is not due to primary or backup
protection to clear faults or due to the expected operation of an SPS and load loss due to tripping of these elements exceeds 1,000 MW. This load
loss does not include consequential load loss due to elements that trip to clear the fault, either as primary or backup protection, load loss due to
expected operation of an SPS or firm load shed performed in accordance with the NERC TPL Standards.
c. Elements are defined as transmission lines, transformers, and generators. A group consisting of all elements within a protective zone is considered
a single element. For example, a three-terminal line is a single element. By itself, a shunt device is not an element.
d. Tripping is assumed to occur at load levels of 125% or higher of the highest emergency rating.
Angular Transient Stability Minimum Damping Ratio (ζ) not to be less than 0.03.
A one-cycle safety margin must be added to the actual or planned fault clearing time.
Page 24 of 28
Table 2. 100 kV and Above Steady-State Bus Voltage Levels
Minimum Voltage, p.u.1
Bus Type
Nominal
kV
Transmission
Buses
Generation Buses6
Maximum
Voltage, p.u.2
Normal3
After First
Contingency4
After Second
Contingency5
161.0
0.95
0.93
0.90
1.05
345.0
0.96
0.94
0.90
1.05
161.0 or
345.0
1.00
0.95
0.95
1.05
Notes:
1. Minimum Voltage values are based on the assumption that no peaking or
intermediate generation will be assumed on line to support voltage prior to the
occurrence of contingencies (outages) except for certain must-run generators
required to maintain facility loadings within facility ratings.
2. Temporary excursions beyond the maximum voltage criteria may be caused by
abnormal system conditions; however, these shall be limited in extent, frequency,
and duration.
3. Normal switching, no outages.
4. After the First 100 kV and above Contingency, voltage must be restorable to the
Normal Minimum Voltage level within one hour after the first contingency.
System adjustments that may be used to restore voltage include adjustment of
transformer load tap changers, switching of capacitor banks and/or reactors,
opening of lines or transformers that do not result in the loss of demand, startup of
generation (usually peaking) and redispatch of generation.
5. After the Second 100 kV and above Contingency, voltage must be restorable to the
First Contingency Minimum Voltage within one hour after the second
contingency. System adjustments include those items listed in note 4 plus
curtailment of firm (non-recallable) power transfers.
6. Generators interconnecting at 100 kV and above are issued a target voltage and a
tolerance band at the point of interconnection consistent with these voltages. It
should be noted that generators interconnecting at 100 kV and above that cannot
physically regulate voltage at the 100 kV and above bus may be issued a power
factor schedule in which case the generator voltages do not apply at these generator
buses; in these cases, the transmission bus voltages will apply at these generator
buses. Generation bus voltages must be met at buses where generation is
connected, is on-line, and is able to control the bus voltage.
March 1, 2016
Page 25 of 28
Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Non-Consequential Load Loss
under footnote 12 is allowed as an element of a Corrective Action Plan in the NearTerm Transmission Planning Horizon of the Planning Assessment, the Transmission
Planner or Planning Coordinator shall ensure that the utilization of footnote 12 is
reviewed through an open and transparent stakeholder process. The responsible entity
can utilize an existing process or develop a new process. The process must include the
following:
1. Meetings must be open to affected stakeholders including applicable
regulatory authorities or governing bodies responsible for retail electric service
issues
2. Notice must be provided in advance of meetings to affected stakeholders
including applicable regulatory authorities or governing bodies responsible for
retail electric service issues and include an agenda with:
a. Date, time, and location for the meeting
b. Specific location(s) of the planned Non-Consequential Load Loss
under footnote 12
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed NonConsequential Load Loss under footnote 12 (as shown in Section II below)
must be made available to meeting participants
4. A procedure for stakeholders to submit written questions or concerns and to
receive written responses to the submitted questions and concerns
5. A dispute resolution process for any question or concern raised in #4 above
that is not resolved to the stakeholder’s satisfaction
An entity does not have to repeat the stakeholder process for a specific application of
footnote 12 utilization with respect to subsequent Planning Assessments unless
conditions spelled out in Section II below have materially changed for that specific
application.
II. Information for Inclusion in Item #3 of the Stakeholder Process
The responsible entity shall document the planned use of Non-Consequential Load
Loss under footnote 12 which must include the following:
1. Conditions under which Non-Consequential Load Loss under footnote 12
would be necessary:
a. System Load level and estimated annual hours of exposure at or above
that Load level
March 1, 2016
Page 26 of 28
2.
3.
4.
5.
6.
7.
8.
b. Applicable Contingencies and the Facilities outside their applicable
rating due to that Contingency
Amount of Non-Consequential Load Loss with:
a. The estimated number and type of customers affected
b. An explanation of the effect of the use of Non-Consequential Load
Loss under footnote 12 on the health, safety, and welfare of the
community
Estimated frequency of Non-Consequential Load Loss under footnote 12
based on historical performance
Expected duration of Non-Consequential Load Loss under footnote 12 based
on historical performance
Future plans to alleviate the need for Non-Consequential Load Loss under
footnote 12
Verification that TPL Reliability Standards performance requirements will be
met following the application of footnote 12
Alternatives to Non-Consequential Load Loss considered and the rationale for
not selecting those alternatives under footnote 12
Assessment of potential overlapping uses of footnote 12 including overlaps
with adjacent Transmission Planners and Planning Coordinators
III. Instances for which Regulatory Review of Non-Consequential Load Loss under
Footnote 12 is Required
Before a Non-Consequential Load Loss under footnote 12 is allowed as an element of
a Corrective Action Plan in Year One of the Planning Assessment, the Transmission
Planner or Planning Coordinator must ensure that the applicable regulatory authorities
or governing bodies responsible for retail electric service issues do not object to the
use of Non-Consequential Load Loss under footnote 12 if either:
1. The voltage level of the Contingency is greater than 300 kV
a. If the Contingency analyzed involves BES Elements at multiple
System voltage levels, the lowest System voltage level of the
element(s) removed for the analyzed Contingency determines the
stated performance criteria regarding allowances for NonConsequential Load Loss under footnote 12, or
b. For a non-generator step up transformer outage Contingency, the 300
kV limit applies to the low-side winding (excluding tertiary windings).
For a generator or generator step up transformer outage Contingency,
the 300 kV limit applies to the BES connected voltage (high-side of
the Generator Step Up transformer)
2. The planned Non-Consequential Load Loss under footnote 12 is greater than
or equal to 25 MW
March 1, 2016
Page 27 of 28
Once assurance has been received that the applicable regulatory authorities or
governing bodies responsible for retail electric service issues do not object to the use
of Non-Consequential Load Loss under footnote 12, the Planning Coordinator or
Transmission Planner must submit the information outlined in items II.1 through II.8
above to the ERO for a determination of whether there are any Adverse Reliability
Impacts caused by the request to utilize footnote 12 for Non- Consequential Load
Loss.
March 1, 2016
Page 28 of 28