ENTERGY TRANSMISSION
PLANNING GUIDELINES
The purpose of this document is to outline and define the transmission planning
guidelines that are used in planning the Entergy Transmission System.
Page 1 of 18
TABLE OF CONTENTS
1.
PURPOSE ............................................................................................................ 4
2.
REFERENCES ...................................................................................................... 4
3.
DOCUMENT REVIEW ............................................................................................. 4
4.
DEFINITIONS ........................................................................................................ 4
5.
RESPONSIBILITIES ............................................................................................... 5
6.
INTRODUCTION .................................................................................................... 5
7.
MODEL DEVELOPMENT ........................................................................................ 6
7.1
Load Flow Analysis Models............................................................................ 6
7.2
Stability Analysis Models ............................................................................... 6
7.3
Access to Models and Related Files.............................................................. 6
7.4
Local Area Model Adjustments ...................................................................... 6
A)
Peak Load Conditions..................................................................................... 6
b)
Low Hydro Generation Conditions ................................................................ 8
c)
Standby Power Requirements........................................................................ 8
d)
Depressed Load Power Factor....................................................................... 8
8.
PERFORMING RELIABILITY ASSESSMENTS ............................................................. 9
8.1
Local Area Assessments................................................................................ 9
8.2
Entergy System-Wide Assessments ............................................................. 9
8.3
Regional Assessments ................................................................................... 9
9.
ADDITIONAL TRANSMISSION PLANNING PRINCIPLES ............................................. 10
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9.1
Reactive Power Requirements ..................................................................... 10
9.2
Power Transfer Limits................................................................................... 10
9.3
Line Loadability Limits ................................................................................. 11
10.
TRANSMISSION SYSTEM ADDITIONS AND RELIABILITY IMPROVEMENTS ................... 13
10.1 Transmission System Additions – Minimum Requirements ..................... 13
10.2 Reliability Improvements.............................................................................. 14
a)
Autotransformers .......................................................................................... 14
b)
Transmission Lines....................................................................................... 15
c)
Voltage Control and Reactive Power Requirements .................................. 16
d)
Automatic Load Shedding ............................................................................ 18
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1.
PURPOSE
The purpose of this document is to outline and define the transmission
planning guidelines that are used in planning the Entergy Transmission
System.
2.
REFERENCES
•
NERC Reliability Standards
(http://www.nerc.com/~filez/standards/Reliability_Standards.html)
•
SERC Supplements
(http://www.serc1.org/Pages/ComplianceContentPage.aspx?ID=6 )
•
Entergy Transmission Local Planning Criteria
•
Entergy’s Facility Connection Requirements
(http://www.entergy.com/transmission/facility_requirements_2004.aspx)
•
Voltage Schedules for Generating Facilities Interconnecting to the
Entergy Transmission System
(http://oasis.e-terrasolutions.com/documents/EES/Voltage_sched-04-0725.pdf)
•
3.
System Impact Study and Facilities Study Process Manual
DOCUMENT REVIEW
This document will be reviewed annually or as appropriate by the Entergy
Transmission Technical System Planning (TSP or Transmission Planning)
group for possible revision. To the extent any modifications are determined
appropriate, such modifications will be supplied to the ICT and be subject to
the provisions of the applicable ICT protocols.
4.
DEFINITIONS
Local Planning Criteria shall mean the transmission local planning criteria
described in this document and referred to as “local reliability criteria” in the
ICT Transmission Planning Protocol.
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Planning Guidelines shall mean the modeling and business practices
described in this document and referred to in Section 2.4(iii) of the ICT
Transmission Planning Protocol.
Subsystem shall mean the various subsystems within the Entergy
Transmission System having natural electrical boundaries. Each
subsystem consists of a network of transmission and sub-transmission
elements that are interconnected with and comprise a part of Entergy's
transmission system. Generally, a subsystem will include a combination of
residential, commercial, and industrial loads along with multiple generation
sources. Each subsystem will usually include one or more load centers
whose load is served from several common sources. A load center is an
area of dense load that can include large cities and/or significant industrial
load. Identified subsystems within the Entergy System include but are not
limited to the transmission system West of the Atchafalaya Basin (WOTAB),
the Western Region (Texas), Lake Charles, Baton Rouge, Amite South,
Downstream of Gypsy (DSG), North LA, Jackson, North MS, South MS,
Little Rock, South AR and North AR.
5.
RESPONSIBILITIES
The development of the Planning Guidelines is the responsibility of the TSP
group. Changes to these criteria shall be governed by the procedures
outlined in the protocols of the ICT Proposal filed in FERC Docket No.
ER05-10-65.
6.
INTRODUCTION
Long-term area planning studies will be performed to evaluate the present
and future performance of the Entergy transmission system in accordance
with NERC Reliability Standards. These studies include individual studies
(load flow, short circuit, stability, transient analysis, and transfer capability
studies) of subsystems throughout the Entergy transmission system. The
purpose of these studies is to identify system constraints and/or reliability
issues and to determine the most cost-effective solutions. The scope of
these studies includes an evaluation of the subsystems for both the nearterm (years 1 through 5) and longer-term (years 6 through 10) planning
horizons. These studies become the basis for Entergy’s five and ten year
transmission system assessment, as well as for the Entergy Construction
Plan to be presented at the annual Transmission Planning Summit. The
ICT will assess Entergy’s Construction Plan and lead the Transmission
Planning Summit as defined in the ICT Transmission Planning Protocol.
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In conjunction with the Local Planning Criteria and the NERC Reliability
Standards and the SERC Supplements to those standards, the Planning
Guidelines are used in performing these planning studies for the Entergy
Transmission System. The Planning Guidelines set forth the modeling and
business practices used to ensure compliance with the Local Planning
Criteria, NERC Reliability Standards and SERC Supplements in a manner
that also reflects the specific characteristics of the Entergy transmission
system.
7.
MODEL DEVELOPMENT
7.1
Load Flow Analysis Models
Load flow models will be developed in accordance with the “Base
Case Model Development” section of the System Impact Study and
Facilities Study Process Manual and the model adjustments
described in these Guidelines.
7.2
Stability Analysis Models
The models for dynamic and transient stability analysis are needbased and are developed depending on the type of study to be
performed. Entergy participates in the SERC EC Intra-Regional
Dynamics Study Group, which develops Regional models for
inclusion in the NERC MMWG dynamics models.
7.3
Access to Models and Related Files
Load flow and short circuit models are available on the Entergy
OASIS web site, and may be downloaded for use by stakeholders.
MMWG Dynamics cases are available through the SERC portal
(www.serc1.org) for a nominal fee. Models relating to specific
studies may also be requested by stakeholders and these models
shall be posted on the Entergy OASIS web site.
7.4
Local Area Model Adjustments
In order to anticipate potential system constraints, long-term area
planning studies should also evaluate each Local Area under various
system conditions including, but not limited to, those listed below.
Additional evaluations under other system conditions may be
necessary.
a)
Peak Load Conditions
Because of the large geographic footprint of the Entergy System, it is
recognized that certain local areas or subsystems will at times reach
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its peak load level non-coincidentally with the System or with other
areas of the System. For this reason and in order to properly plan for
the security and adequacy of these subsystems, Entergy’s
Transmission Planning group will accordingly adjust the peak load
forecasts for these areas that may be non-incident with System.
These areas include EAI, EMI, EGSI-LA, EGSI-TX, ELI-North, ELISouth, and ENOI. The area planners may also consider developing
models for electrical zones, which can cross Entergy Operating
Company boundaries. These zones include but are not limited to
Amite South, Downstream of Gypsy, West of the Atchafalaya Basin
(WOTAB), and Western Region. Each area planner should
coordinate with the planners of the adjacent areas, including those of
other nearby transmission providers, in developing the models.
For each of these local areas, the recorded peak demand should be
normalized to 100 ºF. Entergy deems 100 ºF to be a reasonable
temperature for study purposes on a local area basis because
various regions of the System peak non-coincidentally and
historically have reached extreme temperatures near or above 100
ºF. The procedure by which the local area peak is normalized to 100
ºF is as follows:
•
Determine when the local area or subsystem peaked for the
previous summer season.
•
Determine the average ambient (dry-bulb) temperature for various
weather stations sites within that area for that area’s peak load
day. For example, the recorded temperature at the Houston
airport (IAH) weather station can be used as a proxy for the
average temperature for the Western Region. For areas with a
larger footprint such as WOTAB, it would be prudent and
reasonable to average the daily peak temperatures for various
weather stations including Houston IAH, Beaumont/Port Arthur,
Lake Charles, and Lafayette. The daily peak temperature can be
used, rather than the temperature corresponding to the peak load
hour, since historical data have shown that the daily high
temperatures do not coincide with daily peak loads.
•
The weather normalization factors can be reasonably derived
from values in the following table, which is based on a typical
10,000 MW system. For example, if a local area has a peak load
of 1,000 MW, then the weather normalization factors for this local
area would be approximately 10% of the typical values cited. See
the example below.
Ambient
Temperature
Increase in Demand
per 1 ºF Increment
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Increase in Demand
per 1 ºF Increment for
Range
85 ºF to 90 ºF
90 ºF to 95 ºF
95 ºF to 100 ºF
for 10,000 MW
System
170
160
65
1,000 MW Local Area
25% * 170 = 17
25% * 160 = 16
25% * 65 = 6.5
The model development procedure and process for the System
models is more fully described in the Entergy Procedure for Data
Reporting and System Model Development.
b)
Low Hydro Generation Conditions
Hydro generation is generally plentiful in spring. However, as rainfall
diminishes, hydro generation could be limited during the summer and
fall seasons when load peaks and generation could be limited. The
following considerations should be used when modeling the low
hydro generation scenario: (a) historical operating conditions, (b)
hydro units’ ability to operate as a synchronous condenser, and (c)
hydro units’ availability.
c)
Standby Power Requirements
The Entergy system, especially along the Gulf Coast, contains
numerous co-generating facilities. Such facilities may contract with
Entergy to provide their facilities with standby power. Depending on
the type of contractual agreements, the standby power could be
considered firm. Therefore, the area planners would also have to
evaluate these conditions. Within areas that have multiple standby
power contracts, the area planner should evaluate the system
considering the most limiting single standby power arrangement,
which is based on Entergy’s obligation to meet retail contractual
requirements in the study area as defined in each retail contract.
d)
Depressed Load Power Factor
The System’s reactive power requirements are driven by the load
power factors represented in the models. For the most part, power
factor adjustments and corrections on the distribution system are
addressed by manually-switched capacitor banks. Such banks may
not be operated optimally to meet the summer demands and are
subject to tripping offline line during the occasional summer
thunderstorm. This condition could lead to less than optimal power
factors in certain areas. Thus, it is important for the area planners to
use historical EMS data to validate the true load power factor of
certain areas, especially load pockets. In addition, areas that employ
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extensive underground distribution networks tend to have poorer
power factors than their overhead distribution counterparts.
8.
PERFORMING RELIABILITY ASSESSMENTS
Entergy gauges the adequacy 1 of its transmission system through reliability
assessments. These assessments are conducted using various load flow
models and must satisfy the requirements of the Transmission Local
Planning Criteria, NERC Reliability Standards and SERC Supplements.
There are three types of reliability assessments:
8.1
Local Area Assessments
In order to ensure an appropriate level of reliability for the local
areas, local area assessments are performed using local area
models developed in accordance with Section 7 herein. Local Area
assessments will evaluate compliance with NERC Reliability
Standard TPL-002, the SERC Supplements thereto, and the Load
Pocket Criteria identified in the Local Planning Criteria.
8.2
Entergy System-Wide Assessments
In order to ensure an appropriate level of reliability for the overall
Entergy Transmission System, system-wide assessments are
performed using system models developed in accordance with
Sections 7.1-7.3 herein. The system models do not contain the
adjustments in Section 7.4 and are based on 96 ºF weather
normalization. System-wide assessments will evaluate compliance
with NERC Reliability Standards TPL-001, TPL-003, and TPL-004,
the SERC Supplements thereto, and the Short-Circuit, Stability and
Power Transfer Limits Criteria identified in the Local Planning
Criteria.
8.3
Regional Assessments
In addition to the Local Area and system-wide assessments, Entergy
and the ICT will also participate in coordinated regional planning
studies as prescribed in the ICT Transmission Planning Protocol.
1
NERC defines adequacy as “The ability of the electric system to supply the
aggregate electrical demand and energy requirements of the end-use customers at
all times, taking into account scheduled and reasonably expected unscheduled
outages of system elements.”
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9.
ADDITIONAL TRANSMISSION PLANNING PRINCIPLES
When applying the Local Planning Criteria, NERC Reliability Standards and
SERC Supplements to the reliability assessments described in Section 8
above and the mitigation plans described in Section 10 below, the following
principles should be considered.
9.1
Reactive Power Requirements
The most cost-effective solution will be used to solve voltage or
reactive power problems on the transmission system. Generally,
distribution or transmission capacitor banks are most effective in
reducing transmission reactive power (VAR) requirements, line
losses, and low voltages. Inductive reactors may be needed in cases
of high voltage. Significant VAR production by generators should be
avoided under normal operation except for use under extreme
conditions..
A voltage stability analysis will be used to determine the overall
reactive power requirements for each subsystem and required
margin of dynamic and static reactive power. Area voltage problems
are an indicator of a reactive power deficiency.
9.2
Power Transfer Limits
Transfer capability is the measure of the ability of interconnected
electric systems to reliably move or transfer power from one area to
another over all transmission circuits (or paths) between those areas
under specified system conditions. The units of transfer capability are
in terms of electric power, generally expressed in megawatts (MW).
Transfer capability is also directional in nature. That is, the transfer
capability from area A to area B is not generally equal to the transfer
capability from area B to area A. The electrical ability of the
interconnected transmission networks to reliably transfer electric
power may be limited by thermal, voltage, or stability limits.
a. Thermal Limits – These limits establish the maximum
amount of electrical current that a transmission circuit or
electrical facility can conduct over a specified time period
before it sustains permanent damage by overheating or
before it violates public safety requirements due to thermal
expansion. Normal and emergency transmission circuit
ratings are defined in the Entergy design standards.
b. Voltage Limits - System voltages must be maintained
within the of range acceptable minimum and maximum
voltage limits. For example, minimum voltage limits can
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establish the maximum amount of electric power that can
be transferred without causing damage to the electric
system or customer facilities. A widespread collapse of
system voltage can result in a blackout of portions or the
entire interconnected network. Acceptable minimum and
maximum voltages are network and system dependent.
c. Stability Limits - The transmission network must be
capable of surviving disturbances through the transient and
dynamic time periods (for several seconds) following a
disturbance. References to stability are included in the
NERC Reliability Standards.
d. Contractual Requirements - Some Transmission Providers
have contractual agreements regarding the power transfer
available between them. These agreements have been
approved by the private regulatory agencies.
e. Long-Term Firm Point-to-Point (PTP) and Long-Term
Network Resources – Firm power transfers approved
through appropriate measures by Entergy’s Transmission
Planning department or its successor such as the ICT shall
be guaranteed and maintained per the terms and
conditions of the respective transmission service
agreement.
9.3
Line Loadability Limits
In order to assess the power carrying capability of the transmission
system, it is necessary to know the capabilities of specific
transmission lines. Generally, the capability of a transmission line is
limited by the thermal rating of the conductor or associated terminal
equipment. In some cases, operating criteria such as voltage limits
and stability limits constrain the line loading to level below the
thermal rating. The loading level at which the thermal rating of a line
or an operating criterion -- whichever is more constraining -- limits the
load carrying ability of the line is known as the line loadability.
Transmission line loadability has been a useful concept for the
planning engineer in assessing the loadability limits expressed in
terms of surge impedance loading for transmission lines of various
lengths and voltage classes.
The concept of surge impedance loading (SIL) and the surge
impedance (SI) from which it is derived are very useful quantities in
the line loadability analysis. SI is defined as the characteristic
impedance for the special case of an assumed lossless line. If a line
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is terminated with a load whose Ohmic value is equal to the SI value,
then at exactly at nominal voltage, the line is said to be loaded to 1.0
SIL. At 1.0 SIL loading, the line will neither consume reactive power
from the system nor supply reactive power to the system. Based on
practical considerations and experience, generalized curves of load
carrying capability versus line length are shown in the figure below.
These curves show the loadability of transmission lines in terms of
their surge impedance loading and are widely used in the industry as
a guide for loading the transmission lines. Based on this curve, a
300 mile long line, irrespective of the voltage class can be loaded to
one SIL and a 50 mile line can be loaded to a maximum of 3 times
the SIL value.
The three major limiting factors that set a ceiling on how much power
can be carried by a particular transmission line are:
1. thermal limitations
2. line voltage drop compensation
3. steady state stability limitation
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The thermal limitation is critical primarily in case of low voltage lines. For
EHV lines the practical limitations to line loadability are provided by line
voltage drop and by steady state stability considerations. The voltage
drop limitation across a line is normally set at 5% maximum, and steady
state stability margin of 30-35% is a reasonable level.
It is critical for the transmission planner to take these factors into
consideration when upgrading an existing transmission line or proposing
a new transmission line.
10.
TRANSMISSION SYSTEM ADDITIONS AND RELIABILITY IMPROVEMENTS
Actions to be taken to address reliability issues identified through the
contingency testing and reliability assessments may include (but are not
limited) to transmission system additions and reliability improvements.
Other mitigation plan alternatives are discussed in Section 7.7 of the Local
Planning Criteria. When evaluating the scope of transmission system
additions and reliability improvements required to address a particular
reliability issue, the following principles will apply.
10.1
Transmission System Additions – Minimum Requirements
The operation and planning of the transmission system shall be
conducted so as to preclude uncontrolled break-up and collapse of
the interconnected electric system due to more probable
contingencies. The guidelines described below are intended to
ensure that additions to the transmission system enhance system
security. It is impossible to anticipate and test for all combinations of
contingencies. However, application of these Transmission Planning
Guidelines and the Transmission Local Planning Criteria ensures that
the most probable and consequential contingencies are addressed.
Severe disturbances involving multiple contingencies may cause a
subsystem to become isolated from Entergy's transmission system.
Isolation due to transmission limitations may cause voltage
deficiencies within the subsystem. Therefore, it is desirable to
maintain a transmission system that is not readily susceptible to
isolation. In addition, adequate power transfer capability between
adjacent subsystems should be maintained to assure reliable, costeffective operation of the generation and transmission system.
Additions to the transmission system should be planned according to
the following:
a. Excessive concentration of power being carried on any single
transmission circuit, multi-circuit transmission line, or right-ofway, as through any one-transmission line station shall be
avoided.
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b. Adequate transmission capability shall be maintained to
provide for intraregional, interregional and transregional power
flows under normal and more probable contingency
conditions.
c. Switching arrangements shall be utilized that permit effective
maintenance of equipment without excessive risk to the
electric system.
d. Switching arrangements and associated protective relay
systems shall be utilized that do not limit the capability of a
transmission path to the extent of causing excessive risk to
the electric system.
e. Each subsystem shall maintain service continuity after the loss
of the most important electric network component (either
transmission or generation).
f. Sufficient reactive capacity shall be provided within the
Entergy electric system at appropriate locations to maintain
transmission system voltages within plus 5% or minus 8% of
nominal when more probable contingencies occur.
g. Stability shall be maintained between the subsystem and
neighboring utilities during more probable contingencies
caused by a three-phase fault and single phase fault at the
worst location cleared in normal clearing time according to
Entergy’s protective system design criteria.
h. A subsystem may suffer interruption of load as a result of less
probable contingencies; however, such contingencies shall not
result in widespread disturbances or collapse of the Entergy
electric system.
10.2
Reliability Improvements
a)
Autotransformers
Autotransformer loadings shall be allowed to exceed
nameplate ratings on a case-by-case basis when analyses
have shown that adequate variation exists in the equipment's
duty cycle. An autotransformer’s gas analysis history may be
reviewed if its capability is questionable. Daily peak loadings
of up to 100% of nameplate rating may be allowed as normal
and considered non-harmful to equipment after being
confirmed by analysis of duty cycle. Brief loadings of up to
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130% may be allowed under emergency conditions if
equipment evaluation indicates that such action is acceptable.
Thermal dynamics, gas analysis, and duty cycles of
equipment may be used as appropriate, in lieu of more costly
autotransformer upgrades.
Autotransformers shall normally be sized to provide sufficient
capacity to satisfy expected load requirements over time,
consistent with the economies of equipment relocation and
replacement. Equipment mobility and site access must be
considered in the installation of new facilities and upgrades.
Projects that include autotransformer additions should be
evaluated to assess (a) the advantages of single-phase
versus three-phase units, (b) the need for tertiary windings, no
load taps, load tap changers (LTCs), (c) impedance
requirements, (d) losses, and (e) voltage coordination.
b)
Transmission Lines
Transmission line projects shall be planned so as to maximize
transmission system utilization. Transmission additions and
modifications that result in the under-utilization of portions of
the existing transmission system should be avoided. The
overall efficiency of the transmission system is indicated by
the ability to load all transmission lines without overloading the
most limiting elements. Sufficient flexibility and reliability must
exist in the transmission network to maintain an acceptable
level of customer service.
Transmission line loading under contingency conditions are
acceptable up to 100% of normal line rating. In areas known to
have employed non-conservative construction techniques
resulting in normal line ratings that are marginal at best, line
loadings shall be maintained at or below 100% of the normal
line rating. As mentioned previously, an evaluation can
redefine a line’s critical loading level.
Transmission line additions and upgrades shall be designed
so as to provide sufficient capacity to satisfy projected
transmission growth, consistent with the economic analysis
associated with alternative line additions and upgrades.
Transmission lines may be upgraded to a higher voltage level
to solve voltage or overload problems when economically
feasible and consistent with long range transmission system
plans. To ensure optimal utilization of existing transmission
facilities and prudent application of resources, new
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technologies shall be evaluated as alternatives to traditional
system additions and upgrades. Operational solutions to
adverse transmission system conditions, such as opening
overloaded transmission lines should be considered in lieu of
line additions and upgrades. Where adverse transmission
system conditions can be attributed to a particular network
resource dispatch, a redispatch of the resources should be
considered as an alternative to constructing transmission
facilities. These and all operating guides must not
compromise the reliability of the transmission system, nor
violate Entergy Transmission Local Planning Criteria or
operational procedures.
c)
Voltage Control and Reactive Power Requirements
The most cost-effective solution will be used to solve voltage
or reactive power problems on the transmission system.
Capacitor banks are the most effective means of mitigating
transmission VAR requirements, line losses, and voltage
problems. Inductive reactors may be needed in cases of high
voltage problems. Significant VAR production by generators
should be avoided under normal operation except for use
under extreme conditions. The roles of the various devices in
reactive power planning are further defined below.
1. Transmission customers shall maintain a power factor of
98% at the transmission delivery point or as required by
the service contracts.
2. When it has been determined that transmission customers
are not adhering to the power factor requirements,
Entergy’s Transmission Planning department shall work
with the customer to ensure that power factor corrections
are first addressed on the customer end, and in most of
these cases, power factor corrections are normally made
on the distribution voltage system. Once these corrections
have been made and if transmission voltages are still not
within the acceptable bounds, a transmission solution
should be considered.
3. Transmission capacitor banks shall be utilized to reduce
transmission reactive power flows by compensating for
transmission line reactive power losses. A transmission
capacitor bank may be utilized to alleviate distribution
voltage problems or to meet distribution VAR requirements
only in a situation where a distribution capacitor bank is not
a viable option.
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4. Transmission shunt inductive reactors shall be utilized
when applicable to alleviate high voltage problems on the
transmission system either during switching or steady state
conditions.
5. A static VAR system may be utilized when appropriate and
cost effective to compensate for abrupt variations in VAR
requirements due to changing customer loads or other
transient conditions.
6. Transmission line additions, conversion to a higher
voltage, and upgrades are normally utilized to address
power flow problems rather than to alleviate voltage or
reactive power flow problems. Transmission line additions
and modifications, such as conversion to a higher voltage,
may be appropriate where the addition of either distribution
or transmission capacitor banks is not an option or when
capacitor banks do not significantly increase voltage
support.
7. The opening of transmission lines that support the bulk
power system is not the preferred method of controlling
system voltages, but may be utilized when other voltage
control measures are unavailable.
8. Alternative sources of reactive power, such as those
described above, shall be installed to minimize system
reliance on generators for reactive power production. This
practice allows the generators to operate near unity power
factor, minimizing the impact of a forced generator outage
on the transmission system.
9. Generator voltage set points will be calculated for both
seasonal and hourly variations of system load to provide a
system voltage profile that remains within the operating
guidelines as set forth in this document, under normal and
emergency conditions. See also Entergy’s “Voltage
Schedules for Generating Facilities Interconnecting to the
Entergy Transmission System” posted on
OASIS:http://oasis.eterrasolutions.com/documents/EES/Voltage_sched-04-0725.pdf.
10. Interconnected utilities, including other investor owned
utilities, regional electrical cooperatives and municipalities,
are expected to supply 100% of their reactive power
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requirements and maintain voltage control in accordance
with Entergy's Transmission Planning Guidelines.
d)
Automatic Load Shedding
A major disturbance on the interconnected bulk electric
system may result in certain areas becoming isolated and
experiencing frequency and/or voltage excursions. To
minimize the probability of network collapse, the transmission
system shall be planned for and operated in accordance with
the requirements specified in these guidelines. Analyses of
such events could lead to the implementation of or
enhancements to the underfrequency load shedding (UFLS)
and undervoltage load shedding (UVLS) programs currently
employed on the Entergy system.
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