IDAHO POWER COMPANY
FERC FORM No. 715
PART IV
RELIABILITY CRITERIA
Enclosed

Idaho Power Company’s internal reliability criteria

The Idaho Power Company internal criteria plus the NERC/WECC criteria and other
documents submitted by the WECC constitute Idaho Power Company’s complete
response to FERC for Part IV.
Contact Person:
Mailing Address:
Becky Stewart
P.O. Box 70
Boise, Idaho 83707-0070
E-mail
bstewart@idahopower.com
Telephone Number:
208-388-2284
Facsimile Number:208-388-6647
RELIABILITY CRITERIA
FOR
SYSTEM PLANNING
IDAHO POWER COMPANY
SYSTEM PLANNING DEPARTMENT
Revised February 2009
FERC Form No. 715 2010 Filing
Part IV: Reliability Criteria
Table of Contents
I. Introduction .................................................................................................................1
Philosophy............................................................................................................1
Description ...........................................................................................................1
II. Definitions ..................................................................................................................1
The Transmission System ....................................................................................1
Remedial Actions .................................................................................................2
Loads ....................................................................................................................2
Other Definitions .................................................................................................3
III. Assumptions ..............................................................................................................3
Generation ............................................................................................................3
Equipment Ratings ...............................................................................................4
Upgrade of Transmission Service ........................................................................4
IV. System Performance Requirements ..........................................................................4
Steady-State Voltage Requirements ....................................................................4
Reactive Switching ..............................................................................................4
Post Disturbance Requirements ...........................................................................5
Transient Stability ................................................................................................5
Performance Levels .............................................................................................6
Disturbance-Performance Tables .........................................................................6
Disturbance-Performance Table ..........................................................................8
Performance Levels Table ...................................................................................8
V. Bridger System Performance Requirements ..............................................................9
Pre-Transient (Steady State) Period .....................................................................9
Transient Period ...................................................................................................9
Post-Transient Period ...........................................................................................10
FERC Form No. 715 2010 Filing
Part IV: Reliability Criteria
Idaho Power Company
Reliability Criteria for System Planning
I. Introduction
Philosophy
The Idaho Power Company (IPCo) transmission system is planned to provide cost-effective
and reliable service. The system will have sufficient strength or capacity to maintain
continuity and quality of service to electrical loads during common contingencies or system
disturbances. For certain uncommon contingencies, it is not reasonable to provide enough
capacity to maintain full service, so a reduction in quality of service or even interruption of
service is allowed.
Description
The reliability criteria define the performance requirements for planning the IPCo system.
The performance requirements are given in terms of the effects that are allowed on electrical
loads and the transmission system as a result of various contingencies. The criteria are
deterministic, that is, the same generalized performance is specified for specific types of
contingencies and applied uniformly over the system. Application of the criteria is expected
to provide overall system cost-effectiveness.
The performance criteria for the Jim Bridger system is slightly different than the criteria for
the rest of the system. The Bridger performance criteria is outlined in Section V.
Criteria adopted by the Western Electricity Coordinating Council (WECC), "Reliability
Criteria for Transmission System Planning," limit the effects that disturbances in one system
can have on other systems. The IPCo system is planned to satisfy both the IPCo and WECC
criteria.
II. Definitions
The Transmission System

Main Grid Transmission Service: The transmission lines and related substations that
carry bulk power. The main grid provides the primary connections among major load
areas, large generating plants, major interties, and some intermediate load areas. The
main grid includes all 500 kV, 345 kV, 230 kV, and those lower voltage lines that
perform the main grid function. Those portions of substations, including
transformers, supporting the main grid lines are also included. Examples of these are
the Bridger-Goshen 345 kV, Kinport-Midpoint 345 kV, Boise Bench-Caldwell 230
kV, and Boise Bench-Locust 230 kV lines.
FERC Form No. 715 2010 Filing
Part IV: Reliability Criteria

Improved Radial Service: Any substation on a transmission loop, and the lines in the
loop, where one of the sides of the loop serving the improved radial substation can
better serve normal peak load than the other. Examples include the McCall 138/69
kV loop, the Wood River 138 kV loop, and many of the 46 kV loops in the Southern
and Eastern Division.

Radial Service: A substation and the transmission line that provides the only
connection between the substation and the rest of the transmission system. All
substations along the radial line are included.
Remedial Actions
Remedial action schemes, also known as special protection systems or special stability
controls, are planned protective measures which are initiated following a transmission system
disturbance to provide for acceptable system performance.
Remedial actions, the individual protective measures that make up a remedial action scheme,
are automatic non-continuous supplementary controls that perform functions other than the
isolation of electrical faults. Examples of remedial actions that may be used on the IPCo
system are:

Generator Dropping and/or Ramping: Disconnection or reduction in power output of
certain selected generators to prevent system breakup.

Load Tripping: Disconnection of certain selected loads to prevent system breakup or
voltage collapse.

Load Shedding: Reduction of load by means of underfrequency or undervoltage
relays to prevent disconnection of frequency sensitive generators, minimize frequency
decline, as well as prevent voltage collapse. The amount of load shedding is
optimized such that a minimum amount of load is shed in order to maintain voltage or
frequency criteria.

Reactive Switching: Application or removal of shunt or series capacitors, or shunt
reactors, to prevent system breakup or voltage collapse.

Islanding: Disconnection of a portion of the system from the rest of the
interconnected grid to prevent widespread cascading outages.
Loads

Extreme Peak Load: The seasonal peak load expected for weather conditions that
have a 10% probability of occurrence.

90% Load: The load level that is exceeded less than 10% of the time on a load
duration curve based on normal peak load.

Normal Light Load: The yearly minimum load expected under normal system and
weather conditions.
2
FERC Form No. 715 2010 Filing
Part IV: Reliability Criteria
Other Definitions

Cascading: The uncontrolled successive loss of system elements in which the loss of
each successive element is contingent upon prior loss of elements. Loss of firm or
non-firm load is not considered cascading.

Delayed Clearing: Delayed clearing occurs when the primary protection fails to clear
the fault and backup relaying is required.
III. Assumptions
To assist in the planning process for facility additions, the following assumptions are made:
Generation

Main Grid Generation
Production levels of main grid Idaho Power generation (Hells Canyon, Bridger,
Upper Snake), other utility, and non-utility generation in the Idaho area will be set at
normal seasonal levels or as necessary to meet specific objectives of the study.

Non-Main Grid Generation
Production levels of Idaho Power or non-utility generation embedded in IPCo’s
subtransmission or distribution system will be set at a value to be expected 80% of
the time for the season under study or as needed to meet the objectives of the study.

External Generation
Production levels of external generation outside of the Idaho area will be set as
necessary to meet the objectives of the study.

Variations
Both high and low hydro generation patterns may be evaluated to test the system
under conditions of maximum regional export and import schedules. Other plausible
variations in generation patterns that produce stresses in the transmission system may
also be examined.
Typically, the effects of heavy east and west power flows through the IPCo system
are studied.
Equipment Ratings
Lines, transformers, generators, switch gear, terminal equipment, etc. will be loaded so as not
to exceed applicable continuous or emergency limits established by IPCo.
For long range planning studies, nameplate equipment ratings are typically used for normal
thermal rating. Short-term emergency ratings are typically 110% of nameplate during the
summer and 120% of nameplate during the winter. The short-term ratings infer that
equipment loading can be reduced to the normal thermal rating within an hour.
3
FERC Form No. 715 2010 Filing
Part IV: Reliability Criteria
For near term planning, actual equipment ratings may be determined by performing detailed
studies on the equipment and the involved system.
Upgrade of Transmission Service
The decision to upgrade radial service to improved radial or improved radial to main grid
transmission service must be evaluated on a case-by-case basis and is dependent on
economics and risk. Specifically, some items that should be addressed are:


Upgrade costs
Risk
- Willingness to subject customers to load shedding
- Probability of an occurrence
- Customer loss of load value.
IV. System Performance Requirements
Steady-State Voltage Requirements
The intent of this requirement is to ensure adequate transmission voltage in order to maintain
distribution voltages. Per ANSI specifications, the utility is to provide at the customer's
service entrance a voltage of 1.0 per unit, plus or minus 5% under normal operating
conditions and plus 5.83% or minus 8.33% under emergency conditions. This equates to a
normal operating voltage range of 126 V to 114 V and an emergency range of 127 V to 110
V on a 120 V base.
Generally, for normal operating conditions, transmission voltages are maintained within plus
or minus 5%. The 500 kV voltages range between 500 and 550 kV.
Reactive Switching
Voltage swings caused by any single step of shunt capacitor or reactor switching should
generally not exceed 3% on any load bus with all lines in service. Such swings should not
exceed 5% with any line or transformer out of service or where sufficiently small size
capacitor blocks are not available in standard groups. If acceptable to the customer, swings
of up to 7% may be allowed on an individual customer’s bus where high costs make it
uneconomical to improve performance. The sensitivity of the customer’s load to changes in
voltage as well as the frequency of occurrence are other factors to be considered when
determining maximum allowable voltage swing.
Capacitors or reactors should be added to hold voltage schedules if schedules cannot
otherwise be held on the actual system for normal peak or light load conditions with all lines
in service. Switching capacitor banks or reactors, with all lines in service, should generally
not cause voltage to be outside of the normal operating range.
To meet the steady-state voltage requirements, all regulating equipment, including
generators, must be operated within limits. An allowance, developed from operating records
4
FERC Form No. 715 2010 Filing
Part IV: Reliability Criteria
(generators, capacitors, or reactors) should be made for that equipment which is unavailable
because of scheduled or forced outages.
With normal light loads and low transfer conditions or under other conditions that produce
minimum system loading, it shall be permissible to remove a 230 kV or higher line or lines
from service to keep voltages from exceeding maximum levels. This practice should be used
as a last resort; after all available reactive devices have been switched. The reduced system
must still satisfy all other performance requirements of Section IV and shall not compromise
service reliability.
Post Disturbance Requirements
For all credible outages, voltage stability of the system must be maintained and sufficient
voltage and reactive margin must be provided to ensure that voltage collapse will not occur.
For single contingencies (N-1), the post-disturbance operating point for the critical main grid
transmission busses must maintain a 250 MVAR reactive margin from the point of voltage
instability (nose of the Q-V curve) with successful operation of the remedial action schemes.
And, for double contingencies (N-2), 200 MVAR of reactive margin will be maintained at
the critical main grid transmission busses.
If facilities are overloaded beyond their short term emergency ratings following an outage,
the system will be readjusted such that facilities are within their short term emergency ratings
within 10 minutes. Facility loadings will be further reduced to their continuous levels within
30 minutes of the overloading event. Typically overloads are reduced by:





Insertion/bypassing of series capacitors and/or reactors.
Opening/closing transmission lines and/or transformers.
Adjusting phase shifters (when available)
Re-dispatching generation (if acceptable)
Load dropping (if acceptable)
Transient Stability

Remedial Actions
Remedial actions other than those involving firm load dropping may be used for any
contingencies to maintain stability. Remedial actions involving load tripping or
shedding may be used if the requirements for serving load, as specified in the
Disturbance-Performance Tables, are met.
5
FERC Form No. 715 2010 Filing
Part IV: Reliability Criteria

Faults
Stability must be maintained for a permanent three-phase fault with normal clearing
time or a single-phase fault with delayed clearing. For disturbances specifying a nonthree-phase fault, a double line-to-ground (LLG) fault with normal clearing will be
used. Faults should be applied at the line terminals of the power circuit breaker.
Clearing times should be the sum of guaranteed maximum relay and breaker times for
the fault location being studied.

Load Representation:
IPCo summer or winter load representation should generally be used.

Generation:
Generation should be represented as operated, with governor droop or blocking as
appropriate. The Power System Stabilizer (PSS) should be assumed in service per
WECC guidelines or as otherwise operated.

Damping:
Acceptable system performance requires positive damping of all appropriate machine
quantities, bus voltage, frequency, and tie line power.
Performance Levels
The performance levels for interconnected bulk power systems logically range between a
level having no appreciable adverse system effects and a level where all allowable actions
have been taken and load shedding and islanding may take place. The letters A, B, C, and D
were selected to represent this range of performance.
The A, B, C, and D performance levels are defined in terms of conditions and remedial
actions that may be required on systems other than the one in which the disturbance
originated. These levels are consistent with performance levels defined in the WECC
criteria. The electrical performance requirements for each level are specified in the
disturbance-performance tables.

Level A is system normal with all facilities in-service and all bus voltages,
transmission lines and transformers flows within nominal limits and ratings.

Level B is used to specify performance for single contingencies. No loss of load
should occur and performance should be sufficient to provide good quality of service.
WECC requires that no significant adverse effects occur outside of the IPCo system.

Level C specifies performance for multi-element outages. Firm and interruptible load
shedding may occur for this performance level; however, facility loadings are to
remain within emergency limits. Performance should be sufficient to avoid damage
to customer equipment and no cascading or instability is permitted. The WECC
criteria allow substantial adverse effects to occur outside of the IPCo system.
6
FERC Form No. 715 2010 Filing
Part IV: Reliability Criteria
Disturbances within the Level C performance level have a wide range of probability
of occurrence. For instance, the loss of a bus section is more probable than the loss of
two system elements. Facility upgrades are dependent upon risk and if a particular
outage occurs more often than expected, its performance level requirement may be
changed.

Level D Extreme event resulting in two or more (multiple) elements removed or
cascading out of service. May involve substantial loss of load/generation in a
widespread area or areas. Portion or all of the interconnected system may or may not
achieve a new, stable operating point. These are risk assessment type studies run to
evaluate the performance of the system under unforeseen events. They are normally
studied in evaluating effectiveness of safety net schemes.
Disturbance-Performance Tables
The Disturbance-Performance Tables specify the transmission system performance required
for contingencies that are considered credible events that merit consideration in planning the
IPCo system. Performance levels are given for the main grid, improved radial service, and
radial service. The accompanying Performance Levels Table specifies the requirements to be
met for each performance level.
The following rules are to be observed when applying the tables:

Pre-contingency (System Normal), all bus voltages, transmission lines and
transformers flows within nominal limits and ratings.

Contingencies are credible disturbances that result in automatic disconnection
(momentary or permanent) or emergency manual disconnection of a transmission
facility or generator. This table does not address non-credible contingencies.

The contingencies listed in the table provide a basis for estimating a performance
level to which a disturbance not listed in this table would apply.

During outages, it is permissible to sectionalize the system, reconnect loads, or adjust
generation to control overloads on transformers or lines. Minimum voltage
requirements apply after system adjustments are made.

All multiple contingencies are considered to be independent events except for lines in
the same corridor, pass, or right-of-way or that connect to a common bus or breaker.
Independent contingencies are considered to be non-simultaneous, and 1/2 hour should
be assumed to be available between contingencies for system adjustments.
Dependent contingencies should be considered to occur simultaneously.

System transient and voltage stability must be maintained for all performance levels.

Positive system damping is required for all performance levels A thru C.
7
FERC Form No. 715 2010 Filing
Part IV: Reliability Criteria

The criteria does not permit cascading or subsequent blackout of islanded areas other
than possibly non-credible extreme events studied under category D.
8
FERC Form No. 715 2010 Filing
Part IV: Reliability Criteria
Disturbance-Performance Table
SYSTEM
Main Grid
Transmission
Service
Improved Radial
Service
Radial Service
CONTINGENCY (ELEMENTS LOST)
None (System Normal)
One Generator
One Circuit
One Transformer
Bus Section
Two Generators
Two Circuits
Three or more Circuits on ROW
Entire Substation
Entire Generation Plant including Switchyard
None (System Normal)
Weaker Line
Stronger Line
None (System Normal)
The Radial Line
PERFORMANCE
LEVEL REQUIRED
A
B
C
D
A
C
D
A
All Load Curtailed
Performance Levels Table
REQUIREMENTS
Loads
Serve Extreme Peak Load
Serve 90% Load
Serve Load to Best Ability
Equipment Ratings
Loadings Within Thermal Limits (System Normal)
Loadings Within Emergency Limits
Steady State Voltages (after system adjustments)
Maintain Distribution Bus Voltages Within Normal Range (System Normal)
Maintain Distribution Bus Voltages Within Emergency Range
Post Outage Voltage Deviation of 5% for All System Buses*
Post Outage Voltage Deviation of 10% for All System Buses
Transient Voltages
Max Voltage Dip of 25%; Max Duration of Voltage Dip > 20% = 20 Cycles
Max Voltage Dip of 30%; Max Duration of Voltage Dip > 20% = 40 Cycles
Max Voltage Dip of 30%; Max Duration of Voltage Dip > 20% = 60 Cycles
Transient Frequencies
Minimum Frequency of 59.6 Hz
Minimum Frequency of 59.0 Hz
Minimum Frequency of 58.1 Hz
PERFORMANCE LEVEL
A
B
C
D
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
* Discretionary – Greater than 5% post-outage voltage deviation is acceptable if minimum voltage remains
above nominal of 0.950 per unit.
9
FERC Form No. 715 2010 Filing
Part IV: Reliability Criteria
V. Bridger System Performance Requirements
The Bridger system performance criteria was jointly developed by Idaho Power and
PacifiCorp.
Pre-Transient (Steady State) Period

Bus voltages within the PP&L, UP&L & IPCo systems will be kept within 0.95 and
1.05 per unit.

Equipment loadings will be kept within allowable continuous ratings.

Synchronous condensers at Kinport, Goshen and Brady will be operated at the middle
of their boost-buck range (same amount of dynamic range available in both
directions).

At high transfer levels, the Jim Bridger 345 kV 200 MVAR shunt capacitor bank
should be in-service with Jim Bridger 345 kV voltage at 1.05 per unit.
Transient Period

WECC Reliability Criteria For Transmission System Planning.
Post-Transient Period

For single contingency (N-1), the post-disturbance operating point for the critical bus
must maintain a 250 MVAR reactive margin from the point of instability (nose of the
QV curve) with successful remedial action scheme operation. The Goshen 345 kV
bus is typically the critical bus where the 250 MVAR reactive margin is applied for
loss of the Jim Bridger-Borah 345 kV line.

For double contingency (N-2) in the Jim Bridger transmission system, a 200 MVAR
reactive margin must be maintained at the critical busses in the Idaho Power
transmission system (Borah and Kinport 345/230 kV busses), and a 125 MVAR
reactive margin must be maintained at the critical busses in the PacifiCorp
transmission system (Bridger and Goshen 345 kV busses).

Generation deficiencies, when sufficient, will be allocated amongst all the generating
units within the WECC interconnected system, in accordance with inertia, governor
droop settings or PMAX. Area interchange controls will be blocked.

Generator reactive capability limits will be honored.

Transformer taps, phase shifters and DC converter taps will be assumed to operate in
automatic mode, if so equipped.

No manual (local/remote) reactor or capacitor switching occurs in the Bridger
transmission system during the post-transient period. However, shunt devices
10
FERC Form No. 715 2010 Filing
Part IV: Reliability Criteria
equipped with automatic switching controls and so represented in the power flow case
for other WECC systems will be assumed to operate in automatic mode.

Loss of any one of the 345 kV Bridger lines or the Bridger-Rock Springs 230 kV line
will initiate the following remedial action scheme: Switching in a 175 MVAR shunt
capacitor bank at Kinport 345 kV at ten cycles, bypassing the Burns series capacitor
bank and switching in a 50 MVAR shunt capacitor bank at Goshen 161 kV at 12
cycles, and switching in an additional 50 MVAR shunt capacitor bank at Goshen 161
kV at 42 cycles. Cycles are counted from the fault inception.

Line and transformer loadings will not exceed emergency ratings.
11