HomeMy WebLinkAboutASCC Planning Critiria for the Reliability of Interconnected Electric Utilites 5-1991ALASKA SYSTEMS COORDINATING COUNCIL
An association of Alaska's electric power systems
Promoting improved reliability through systems coordination
ASCC PLANNING CRITERIA
for the reliability of interconnected electric utilities
May 1991
ALASKA SYSTEMS COORDINATING COUNCIL
ASCC PLANNING CRITERIA
FOR THE RELIABILITY OF INTERCONNECTED ELECTRIC UTILITIES
The Alaska Systems Coordinating Council (ASCC) is an association of Alaska’s electric
power systems promoting improved reliability through systems coordination and an affiliate
member of the North American Electric Reliability Council (NERC). In August, 1990, the
ASCC established a Reliability Criteria Subcommittee composed of representatives of the
ASCC members in Alaska’s Railbelt region. The primary task of that Subcommittee was
to complete efforts to develop, formulate in writing, and submit to ASCC for approval,
coordinated interconnection planning and operating reliability criteria.
The ASCC Planning Criteria for the Reliability of Interconnected Electric Utilities were
prepared for use by the ASCC members in planning and designing generation and
transmission network facilities of the interconnected Railbelt utilities. In concert with the
planning policies of NERC, the overall framework was provided by the NERC Planning
Guides adopted by the NERC Engineering Committee in 1989 that describe good practices
for bulk electric system planning. Individual ASCC planning criteria corresponding to the
Guides were then developed specifically for the Alaskan interconnected bulk power system.
The criteria provide guidance to the utilities in evaluating electric system performance over
the planning horizon and provide requirements and recommendations to be considered in
planning and designing additions and modifications. Application of the criteria will promote
the reliability of the bulk power system of the interconnected electric utilities of Alaska.
Included herein are:
NERC Planning Guides and corresponding ASCC Planning Criteria .... Page 1
The ASCC Planning Criteria .... 1... cece eee eee eee eens Page 2
NERC Terms and Definitions i 60% si6 cca cea ose oa0 cas Foes wae oe Page 17
Recommended by Reliability Criteria Subcommittee: February 19, 1991
Adopted by the Alaska Systems Coordinating Council: April 4, 1991
North American Electric Reliability Council
Planning Guides
These Planning Guides describe the characteristics of a reliable bulk electric system. They
are intended to provide guidance to the Regional Councils, Subregions, Pools, and/or the Individual
Systems in planning their bulk electric systems.
° To the extent practicable, a balanced relationship is maintained among bulk electric system
elements in terms of size of load, size of generating units and plants, and strength of
interconnections. Application of this guide includes the avoidance of:
Excessive concentration of generating capacity in one unit, at one location or in one
area;
Excessive dependence on any single transmission circuit, tower line, right-of-way, or
transmission switching station; and
Excessive burdens on neighboring systems.
° The system is designed to withstand credible contingency situations.
° Dependence on emergency support from adjacent systems is restricted to acceptable limits.
° Adequate transmission ties are provided to adjacent systems to accommodate planned and
emergency power transfers.
° Reactive power resources are provided which are sufficient for system voltage control under
normal and contingency conditions, including support for a reasonable level of planned
transfers and a reasonable level of emergency power transfer.
° Adequate margins are provided in both real and reactive power resources to provide
acceptable dynamic response to system disturbances.
° Recording of essential system parameters is provided for both steady state and dynamic
system conditions.
° System design permits maintenance of equipment without undue risk to system reliability.
° Planned flexibility in switching arrangements limits adverse effects and permits
reconfiguration of the bulk power transmission system to facilitate system restoration.
° Protective relaying equipment is provided to minimize the severity and extent of system
disturbances and to allow for malfunctions in the protective relay system without undue risk
to system reliability.
° Black start-up capability is provided for individual systems.
° Fuel supply diversity is provided to the extent practicable.
(NERC Planning Guides as approved by NERC Engineering Committee on February 28, 1989)
ASCC
Planning
Criteria
ASCC criteria
correspond to
Planning Guides as
follows:
Criteria #1
Criteria #2
Criteria #3
Criteria #4
Criteria #5
Criteria #6
Criteria #7
Criteria #8
Criteria #9
Criteria #10
Criteria #11
Criteria #12
ASCC Planning Criteria #1: Balance Among System Elements
A balanced relationship shall be maintained among bulk electric system elements so as
to avoid excessive dependence on any one element.
Requirements
Planning for future development of the interconnected generation and transmission
system shall ensure a balance among the system elements such that the following shall be
avoided:
1, Excessive concentration of generating capacity in one unit, at one location, or in
one area.
2. Excessive dependence on any single transmission circuit, tower line, right-of-way,
or transmission switching station.
3. Excessive burdens on neighboring systems.
Recommendations
1. Utilities should conduct power flow and dynamic system studies to verify that
plans for additional generation, including their size and locations, do not adversely
impact the interconnected system or individual utilities.
2. No more than one-fourth of the total interconnected installed generation should
be located at any one generating site.
3. The maximum size of planned future generation units should be established such
that system stability is maintained.
4, Generation should be distributed throughout the system so that loss of the largest
generator will not cause system instabilities or uncontrolled cascading to blackout.
3: Plans for additional generation sites should include integrating transmission such
that its full plant output can be maintained under any single transmission
contingency.
6. Sufficient installed capacity reserves above loads should be planned such that the
calculated loss of load probability does not exceed one day in ten years.
he The system should have the ability to provide adequate spinning reserves under
automatic generation control (or accepted load-shedding schemes) such that
individual interconnected areas will avoid outages cascading to total blackout
whenever area intertie facilities experience outages.
ASCC Planning Criteria #1, Page 1 of 2 2
8. Generation or transmission system additions or improvements should be planned
to come on-line at the time a transmission facility is projected to reach 90 percent
of its continuous rated capability.
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ASCC Planning Criteria #1, Page 2 of 2 3
ASCC Planning Criteria #2: Contingencies
Additions to the interconnected system shall be planned and designed to allow the
interconnected system to withstand any credible contingency situation without excessive
impact on the system voltages, frequency, load, power flows, equipment thermal loading,
or stability.
Requirements
The following contingencies shall be used for planning and design of the interconnected
system:
1. Single Contingency:
1:1.
1.2.
1.3.
1.4.
15.
Fault on any line end, assuming that the primary protection removes the
faulted line section and has one unsuccessful reclose, if appropriate.
Loss of any single transformer or line.
Starting or loss of any generator or static Var system.
Acceptance or loss of a large load; e.g. that load being carried on an
intertie or major load center.
Loss of any substation bus section.
2. Multiple Contingency:
2.1. Loss of entire generating station or transmission substation.
2.2. Loss of any double circuit structure.
2.3. Loss of all transmission lines in common right-of-way.
2.4. Acceptance or loss of a major load center, after first contingency.
2.5. Fault on any line end, assuming that the breaker or transfer trip fails and
requires the operation of the back up relay scheme to remove the faulted
section of line.
Recommendations
ds All facilities should remain below their emergency rating following any single or
multiple contingency occurrence.
2, All testing and verification studies should be performed at peak and off-peak load
and generation levels.
ASCC Planning Criteria #2, Page 1 of 2
3s There should be no loss of load on a system for the more common single
contingency disturbances originating on other systems, except for load shedding to
stabilize extreme frequency decay which would cause uncontrolled area-wide
power interruptions. The uncontrolled loss of load is unacceptable even under
the most adverse credible disturbances.
4. During all excursions subsequent to the occurrence of any single contingency, the
following parameters should be maintained within applicable emergency limits
without system separation or instability:
4.1. Voltage Level: Minimum Maximum
First Power Swing: 0.80 pu V 1.10 pu V (for 0.5 sec.)
Intermediate: 0.92 pu V 1.05 pu V
Steady State: 0.95 pu V 1.05 pu V
4.2. Frequency: 58.8 Hz 61.5 Hz
5. Load-shedding should be planned for adequate system response to multiple
contingencies to avoid system collapse.
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ASCC Planning Criteria #2, Page 2 of 2 5
ASCC Planning Criteria #3: Emergency Support
Reserves should be provided such that emergency support from adjacent systems is
restricted to acceptable limits as determined by studies of the interconnected system.
Requirements
Emergency support from adjacent systems shall be used only as a temporary source of
emergency energy and system capacity is to be promptly restored so that the
interconnected system will be prepared to withstand the next contingency.
Recommendation
A utility should not plan for the availability of routine or emergency support from an
adjacent utility, except as specifically provided for in individual or joint utility
agreements.
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ASCC Planning Criteria #3, Page 1 of 1
ASCC Planning Criteria #4: Support From Adjacent Systems
Adequate transmission ties between adjacent systems shall be provided to accommodate
planned and emergency power transfers.
Requirements
Transfer limits for planned emergency power transfers between adjacent systems shall be
verified by static, dynamic, and voltage stability analyses to ensure compliance with all
Planning Reliability Criteria.
Recommendations
de Transmission ties should be designed to carry emergency transfers following any
single contingency on the interconnected system.
2. Transmission ties should be retained between control areas to the maximum
extent practical following a multiple contingency on the interconnected system.
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ASCC Planning Criteria #4, Page 1 of 1 7
ASCC Planning Criteria #5: Reactive Power Resources
Each control area shall provide sufficient capacitive and inductive resources at proper
levels to maintain system steady state and dynamic voltages within established limits,
including support for reasonable levels of planned and emergency power transfers.
Requirements
1. Devices shall be installed on each system to regulate the transmission voltage and
reactive power flow levels, and to keep voltage levels within allowable limits.
Devices shall be sized for response to dynamic excursions and to control voltage
and power flow in a stable state, once the faulted section has been removed from
the system.
Sizing and location of static Var systems shall be such that any single contingency
shall not result in the loss of the static Var system.
All reactive resource equipment shall be capable of continuous operation during
system frequency excursions resulting from credible contingencies.
Reactive resources shall be sized and provided with controls sufficient to start,
operate, and stop them without causing undue adverse system effects.
Recommendations
1. Each control area should be able to demonstrate and verify that the equipment
has the capability and is responsive to the deficiencies resulting from credible
system contingency disturbances, arresting any subsequent system deficiency, and
maintaining the system in a stable operating mode.
The size, number, and location of static Var systems, capacitor banks, and reactor
banks should be considered in heavily compensated lines which could become
unstable due to loss of one static Var system. Reactive resources should be sized
and located to minimize the impacts of flicker due to starting, energizing, stopping
or de-energizing the devices.
Static Var systems should be designed to be capable of unconstrained use in the
presence of credible harmonics, geomagnetic induced currents and credible
frequency swings.
Each system should plan and size all reactive supply devices for islanding, in total
or in part, from interconnected resources, to control high voltage on open ended
lines, and to maintain all voltages and power flows within appropriate limits.
Reactive control devices should have the capability of being monitored or
controlled through a supervisory control and data acquisition (SCADA) system.
ASCC Planning Criteria #5, Page 1 of 1 8
ASCC Planning Criteria #6: Real and Reactive Power Margins
Margins in both real and reactive power resources are provided for acceptable dynamic
response to system disturbances.
Requirements
i. Each system shall provide adequate responsive generation capable of providing
adjustments in the area generation to return Area Control Error to zero, or
reduce area load to match area generation and thus return frequency to nominal
levels.
2. Each control area shall provide a method of regulating generation capability to
provide for adequate system regulation.
3s Devices shall be provided in each system to keep voltage level and power flow
within allowable limits.
4. Devices shall be sized for response to dynamic excursions and control frequency,
voltage, and power flow in a stable state, once the faulted section has been
removed from the system.
Recommendations
1. Provisions to adjust real power should be provided to respond to credible
contingencies through the use of generation with responsive automatic generation
control, load shedding, unit tripping, braking resistors, either individually or
through the use of combinations of the above.
2s Provisions to adjust reactive power should be provided to respond to credible
contingencies through the use of generation excitation response, automatically
switched capacitors, reactors, static Var systems, either individually or through the
use of combinations of the above.
Ds Devices should be planned and sized to control expected voltage excursions while
staying within their ratings without tripping from either thermal or "ceiling"
limitations which could subsequently trip off the device.
4. Devices which are installed to provide response to disturbances should be
operated at levels which will allow each device to supply the intended duty
without tripping the device.
ASCC Planning Criteria #6, Page 1 of 2 9
5: Each control area should be able to demonstrate and verify that the equipment is
responsive to the deficiencies following credible system contingency disturbances,
and capable of arresting any subsequent system deficiency and maintaining the
system in a stable operating mode.
6. Based on the low system inertia and relatively fast frequency reduction following
the loss of large generation blocks on the interconnected system, load shedding
may be acceptable and required to control frequency decay.
a Each area and control area should plan and size all real and reactive supply
devices for islanding in total or in part from interconnected resources to maintain
all voltages, frequencies, and power flows within appropriate limits.
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ASCC Planning Criteria #6, Page 2 of 2 10
ASCC Planning Criteria #7: Recording System Parameters
Essential system parameters shall be recorded.
Requirements
Ls Adequate equipment shall be installed to record system conditions with respect to
load, generation, transmission line loading, voltage and frequency as required to
provide information to determine if system operation is within established limits.
2. System conditions shall be sufficiently recorded to allow determination of the
cause of system outages or disturbances.
Recommendations
1 SCADA systems should adequately verify steady state system operating
parameters and provide alarms for significant parameters.
is Equipment such as dynamic system monitors, event recorders, etc., should be
installed at potential stability problem areas and major interconnection points.
Such devices should be capable of remote interrogation.
3; Consideration should be given to the utilization of automatic equipment to bring
immediate attention to important deviations in system operating conditions and to
indicate or initiate corrective action.
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ASCC Planning Criteria #7, Page 1 of 1 11
ASCC Planning Criteria #8: Reliability During Maintenance
System designs shall allow for equipment maintenance without unduly degrading
reliability.
Requirements
The interconnected system shall be designed to withstand any credible contingency
situation without excessive impact during scheduled maintenance.
Recommendations
1, Design of all major system components should meet the above criteria.
2; Interconnected system planning should consider coordinated annual maintenance
schedules to minimize exposure to system disturbances.
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ASCC Planning Criteria #8, Page 1 of 1 12
ASCC Planning Criteria #9: Switching Flexibility
Switching arrangements shall be provided to limit adverse effects and permit
reconfiguration of the bulk power transmission system to facilitate system restoration.
Requirements
1 All utilities shall provide for reconfiguration at critical facilities; that is, ring bus,
auxiliary bus, or similar schemes shall be provided.
2. Switches shall be installed as required on long lines, reactors, capacitors, or other
equipment that may require system reconfiguration for system restoration.
Recommendations
1 Consideration should be given to providing emergency ties for backup for
transmission or substation facilities which do not meet normal single contingency
requirements.
25 Consideration should be given to SCADA control of switching within the bulk
transmission system to aid in restoration.
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ASCC Planning Criteria #9, Page 1 of 1 B
ASCC Planning Criteria #10: Protective Relaying
Provide sufficient relaying equipment such that the severity and extent of system
disturbances is minimized and that malfunctions in the protective relay system do not
jeopardize system reliability.
Requirements
1, Protection schemes shall be designed so that relay operations will reliably remove
faulted system components within the time frame required to maintain system
stability, while at the same time avoiding unnecessary removal of unfaulted
components.
2; Primary and backup protective relays on the generation and transmission system
shall be of complementary types and/or manufactures to minimize risks arising
from common mode failures of identical instruments.
3s Relaying shall be set to balance the protection of both individual generating units
and the overall system.
4. Railbelt utilities shall coordinate relay protection schemes and settings.
3. All protective relaying components on the generation and transmission system
shall be provided with provisions for periodic testing to verify designed operation.
Recommendations
1. Any line protective relaying function required to maintain system stability should
have multiple redundant protective relaying schemes, the extent of such
redundancy to be determined through studies of the specific relaying applications.
2. Breaker failure relaying should be provided at both generation and transmission
substations.
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ASCC Planning Criteria #10, Page 1 of 1 14
ASCC Planning Criteria #11: Black Start-up
Black start-up capability is to be provided for individual systems.
Requirements
1. Pw Equipment for black starts shall be specified to cover emergency conditions,
including the loss of communications between area control centers.
Provisions for black starts shall be developed with the intent of restoring the
integrity of the interconnected system.
Planning for black starts shall be coordinated with adjacent systems.
Control centers shall be provided with back-up power supplies for a sufficient
period of time.
Recommendations
1. When designing a generating unit, an outside source of power for generating unit
start-up should be included or adequate redundant transmission provided for
emergency start-up capability.
The following should be considered when planning transmission system voltage
compensation.
2.1. | Shunt capacitors or reactors should be placed on the electrical system to
allow re-energization of lightly loaded transmission lines with the ability to
compensate at the closest available location.
2.2. Effects of energizing high voltage cables at the end of a long, lightly loaded
line should be considered when sizing reactors.
2.3. The capability of the generators to provide or absorb Vars should be
considered when sizing dynamic or switched compensation.
2.4. The limits on the automatic voltage control devices and protective time
delays should be considered when designing the transmission system.
Adequate automatic synchronizing locations and equipment should be provided to
enable system operators to readily respond to system disturbances.
Each generating plant should have a source of emergency power to expedite
restarting. Hydroelectric plants should have internal provisions for restarting.
Back-up voice telecommunications facilities, including emergency power supplies
and alternate telecommunication channels should be provided to assure
coordinated control of operations during the restoration process.
Control centers using SCADA systems should consider providing single point
control for tripping and restoring each station to expedite restoration and
shedding of load.
ASCC Planning Criteria #11, Page 1 of 1 15
ASCC Planning Criteria #12: Fuel Supply
Plans for generation additions shall consider fuel supply diversity.
Requirements
1, Fuel availability analyses and economic studies of alternate fuel types shall be
performed whenever utility long-range planning indicates the need for additional
generation. Such studies shall consider the likelihood and impacts of fuel price
variations and fuel shortage scenarios.
2. Studies of the adequacy of fuel supplies for planned generation additions shall be
conducted to verify that such supplies are sufficient for projected unit operations
over the expected life of the planned unit(s).
Recommendation
Diversity of supply sources, transportation methods, and storage requirements should be
considered in plans for future generation.
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ASCC Planning Criteria #12, Page 1 of 1 16
North American Electric Reliability Council (NERC)
Actual Interchange:
Adequacy:
Assessment:
Automatic Underfrequency Load
Shedding:
Availability:
Avoided Cost:
Biomass:
Bulk Electric System:
Capability:
Capacity:
Capacity Margin:
Capacity with Full Reserve:
Capacity without Reserve:
Cogenerator:
Coincident Peak Demand:
Connecting Utility:
Conservation:
Terms and Definitions
Metered electricity that flows from one control area to another.
The ability of the bulk power electric system to supply the aggregate electric power
and energy requirements of the consumers at all times, taking into account
scheduled and unscheduled outages of system components.
To compare against a norm or standard or to compare among units of a group.
The disconnecting of lines or transformers, and thereby customers, through the use
of relays actuated by a lowering of the system frequency below 60 Hz.
Availability is a term describing the readiness of a unit to generate electricity, even
though the unit may not be generating at that moment.
The cost an electric utility would otherwise incur to generate power if it did not
purchase electricity from another source.
Any organic material not derived from conventional fossil fuels. Examples are
animal waste, agricultural or forest by-products and municipal refuse.
The generation and transmission network facilities of an electric system.
Synonymous with capacity.
A measure of the ability to generate electric power, usually expressed in
megawatts or kilowatts. Capacity can refer to the output of a single generator, a
plant, an entire electric system, a Power Pool or a region.
The difference between Capacity and Peak Demand divided by Capacity. The
Capacity Margin is often expressed in percent by multiplying by 100.
The highest (in availability) form of capacity transaction. The system is obligated
to deliver power and energy at a specific degree of reliability. The selling system
must purchase power or take other appropriate actions before curtailing the
transactions.
A transaction in which the capacity is supplied when available from the aggregate
of generating units of the seller. The seller does not have to deliver power and
energy whenever certain system conditions exist that would impose undue hardship
on the seller.
A facility which produces both electric energy and steam or forms of useful energy
(such as heat) which are useful for industrial, commercial heating or cooling
purposes.
The Peak Demand for a group of systems in combination, i.e., the Peak Demand
one would see if the group were a single system.
The utility to which the non-utility generator is connected. (Often referred to as
the "host utility”.)
Implementation of measures that decrease energy consumption of targeted end
uses resulting in beneficial load shape changes, often by encouraging the use of
more efficient appliances and equipment.
NERC Terms and Definitions, Page 1 of 6 17
Contingencies:
Contingency:
Control Area Utility:
Control Area:
Criteria:
Demand or Load:
Electric Utility:
Electrical Energy:
Extreme Contingencies:
Forced (Unplanned) Outage:
Fuel Cell:
Inadvertent Interchange:
Inoperable:
Events on the bulk electric system which could adversely affect its reliability.
The unexpected failure or outage of a system component (generator, transmission
line, breaker, switch, etc.).
The utility operating the control area in which the non-utility generator is located.
An electric system(s) capable of regulating generation to maintain interchange
schedule(s) with other systems and to contribute its obligation to help maintain
Interconnection frequency.
The measuring systems and performance standards used for assessing the actual
or projected reliability of a given bulk electric system. Failure to attain a specified
performance standard indicates the need to consider adding or rearranging
facilities, changing operating modes or other responses. Examples of criteria that
might apply to planning for generation adequacy are:
a) Generating Capacity Margin
b) Loss-of-Load Probability
c) Loss-of-Energy Probability
Examples of criteria that might apply to simulated testing of the bulk electric
system are:
a) No cascading following any of a specified set of contingencies
b) No overloaded facilities following a specified contingency
c) All voltages within prescribed limits
The instantaneous electric requirement of a power system, usually expressed in
units such as megawatts (MW) or kilowatts (KW).
Any entity owning and operating an electric system for the purposes of sale or
resale to the end users.
The generation or use of electric power by a device over a period of time, usually
expressed in watthours, kilowatthours (Kwh), megawatthours (MWh), or
gigawatthours (GWh).
Events or combinations of events which have a low probability of occurring, would
severely stress the system, and have the potential to lead to a widespread cascading
outage.
(Generating Unit) The occurrence of an unplanned component failure (immediate,
delayed, postponed) or other condition which requires that a generating unit be
removed from service immediately or before the next weekend. A forced
(unplanned) derating occurs when the load on a generating unit must be reduced
immediately or before the next weekend.
A device in which a chemical process is used to convert a fuel directly into
electricity.
The difference between a control area’s actual interchange and scheduled
interchange.
Capacity out of service for reasons such as being limited by environmental
restrictions, legal or regulatory restrictions, extensive modifications or repair, or
capacity specified as being in a mothballed state.
NERC Terms and Definitions, Page 2 of 6 18
Interchange:
Interconnection:
Internal Demand:
Interruptible Customer:
Interruptible Load:
Involved Utility:
Load Management:
Load Shedding:
Loss (ASCC Reliability Criteria
Subcommittee definition):
Loss of Load Probability:
Margin:
More Probable Contingencies:
Net Capacity:
Net Demonstrated Capacity:
Net Dependable Capacity:
Non-coincident Peak Demand:
Electricity that flows from one control area to another.
When capitalized (Interconnection), any one of the four bulk electric system
networks in North America: Eastern, Western, Quebec, and Texas. When not
capitalized (interconnection), the facilities that connect two systems or control
areas.
The maximum integrated clock hour sum of the demands of all customers which
a system services, plus the losses incidental to that service. Internal Demand is
quantified by summing the metered (net) outputs of all generators within the
system, plus the metered line flows into the system, minus the metered line flows
out of the system.
A utility customer that, by contract or tariff, can be shed by the utility before
shedding other customers.
Customer demand that can be curtailed, i.e., interrupted, by action of the system
operator in accordance with contractual arrangements.
Any and all utilities that play a role in delivering electric energy from the non-
utility generator to the purchasing utility. This may include the connecting utility,
one or more control area utilities, the wheeling utility, the purchasing utility, or
any other utility impacted by the non-utility generator’s operation.
A procedure in which customer demand can be controlled through the direct
action of the system operator through actual interruption of electric supply to
individual appliances or equipment on the customer’s premises.
Disconnecting or interrupting the electrical supply to a customer load by the
utility, usually to mitigate the effects of generating capacity deficiencies or
transmission limitations.
Unscheduled unavailability of a system component.
A measure of the expectation that system demand will exceed capacity during a
given period, often expressed as the expected number of days per year.
The difference between capacity and peak demand. Margin is usually expressed
in megawatts.
Events which are more likely to occur, but which have a less severe impact on
system reliability than extreme contingencies.
The gross capacity of a generating unit as measured at the generator terminals less
the power required for the auxiliary equipment (such as fan motors, pump motors
and other equipment essential to operate the unit).
Synonymous with Net Dependable Capacity.
The maximum capacity modified for ambient limitations which a generating unit,
power plant or system can sustain over a specified period of time, less the unit
capacity used to supply the demand of that unit’s station service or auxiliary needs.
The sum of individual systems’ Peak Demands, regardless of when they occur.
Non-coincident Peak Demand will always be greater than or equal to the
Coincident Peak Demand.
NERC Terms and Definitions, Page 3 of 6 19
Non-utility Generator:
Parallel Flow:
Peak Demand:
Power Pool:
Purchasing Utility:
R/W (Right-of-Way):
Rating:
Reactive Power:
Regional Council Criteria:
Regional Council:
Regional Reliability Council:
A general term embracing facilities named in the Public Utilities Regulatory
Policies Act (cogenerators and small power producers) and any other non-utility
generating facilities connected to the utility system. Facility for generating
electricity which is not exclusively owned by an electric utility and which operates
connected to an electric utility system.
Electric flow on a utility's transmission system resulting from electricity flows
scheduled on any other system. Electricity flows on all parallel paths in amounts
inversely proportional to each path’s impedance.
A buyer, producer, or wheeler of electricity in an interchange agreement or
contract.
The highest electric requirement experienced by a power system in a given period
of time (e.g., a day, month, season or year). In practice, Peak Demand is
calculated by dividing the energy used over a short period of time, usually an hour,
by the length of that period of time.
Two or more interconnected power systems operated as a system and pooling their
resources to supply the power and energy requirements of the systems in a reliable
and economical manner.
The utility that is purchasing electrical energy or capacity from another utility or
non-utility generator.
The corridor of land within which transmission lines are routed and within which
the owning utility has certain rights of access and construction.
The output capability of a generator determined under specified conditions. The
rating of a transmission line is its capability to carry electric current, as determined
under specified conditions.
The portion of power that establishes and sustains the electric and magnetic fields
required to perform useful work. Reactive power must be supplied to most types
of magnetic equipment, such as motors in refrigerators and air conditioners, and
to heavily loaded transmission lines. It is supplied by generators, synchronous
condensers, or electrostatic equipment, such as capacitors. It directly influences
the electric system voltage.
Criteria applied within a Council to assess the interaction of the plans of individual
utilities for the bulk electric system facilities within the Council. These criteria
include methods and procedures for rating generating units and other facilities,
data systems and intersystem protection philosophies, and the specification of
simulated tests to be performed. In some cases, these activities are carried out as
function of an area or subregional group within a Regional Council, in which case
there would be area or subregional criteria.
One of nine electric Reliability Councils that form the North American Electric
Reliability Council (NERC). (NERC was formed in 1968 by the electric utility
industry to promote the reliability and adequacy of the bulk power supply in the
electric utility systems of North America.)
One of nine electric Reliability Councils that form the North American Electric
Reliability Council (NERC).
NERC Terms and Definitions, Page 4 of 6 20
Reliability:
Reserve Margin:
Reserve:
Scheduled Interchange:
Security:
Special Protection Systems:
Standby Power:
System Criteria:
System:
Transmission System:
Trip:
Unavailable Capacity:
In a bulk electric system - - the degree to which the performance of the elements
of that system results in power being delivered to consumers within accepted
standards and in the amount desired. The degree of reliability may be measured
by the frequency, duration,and magnitude of adverse effects on consumer service.
Reliability can be addressed by considering two basic and functional aspects of the
bulk electric system - adequacy and security.
The difference between Capacity and Peak Demand divided by Peak Demand.
The Reserve Margin is often expressed in percent by multiplying by 100.
Synonymous with Margin.
Electricity scheduled to flow between control areas, usually the net of all sales,
purchases, and wheeling transactions between those parties at a given time.
The ability of the bulk power electric system to withstand sudden disturbances
such as electric short circuits or unanticipated loss of system components.
Designed to perform system protection functions other than the isolation of
electrical short circuits. They are used to automatically reconfigure the electric
system by disconnecting generators, opening lines, shedding load, and other actions
to maintain stability or control power flows on surviving critical facilities
immediately following a disturbance on the system.
Power used to serve customer demand in accordance with contractual
arrangements to provide power and energy to a customer (often for an industrial
customer having his own generation) as a second source or backup for the outage
of the primary source. Standby Power is intended to be used infrequently by any
given customer.
Criteria used by individual utilities, or other entities which have financial
responsibility for commitment of new facilities, in planning facilities or assessing
plans. These criteria include methodologies for testing and measuring system
performance and may include indices of satisfactory performance.
The physically connected generation, transmission, distribution and other facilities
operated as an integral unit under one control, management or operating
supervision, often referred to as “electric system", “electric power system" or
"power system".
A network of transmission lines and the substations to which the lines are
connected.
To disconnect a system component by opening the circuit breaker(s) or other
switch(es) that connect it to the system, usually to isolate or disconnect a failed
system element to protect it and the rest of the of system from damage or to
perform maintenance.
The amount of Capacity that is known, expected or statistically predicted to be not
available to meet system demand during the period of time being considered.
Known or expected Unavailable Capacity includes capacity out of service due to
scheduled unit maintenance and deratings. Statistically predicted Unavailable
Capacity includes unplanned or forced outages, outages that are planned with a
short lead time, and capacity limitations as a result of temporary operating
conditions.
NERC Terms and Definitions, Page 5 of 6 21
Unit Power:
Voltage Reduction:
Wheeling Customer:
Wheeling Utility:
Wheeling:
Power from one or more specific generating units. Unit Power purchases and
sales are forms of capacity transactions without full reserve. Capacity is sold from
one or more specific units for a certain period of time. Delivery of power and
energy is contingent on the unit being available.
A means to reduce the demand on a utility by lowering the voltage. Usually
performed on the distribution or subtransmission system.
Any party contracting with a utility for wheeling service on that utility's
transmission system. The party may either be the producer or purchaser of the
electricity being wheeled.
A utility providing transmission service for another party’s electricity.
The use of the transmission system facilities of one or more parties to transmit
electricity for another party.
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