Glossary

NERC Terminology Glossary

Glossary of terms used in NERC Reliability Standards and adopted by the NERC Board of Trustees from February 8, 2005, through March 29, 2022.

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Actual Frequency (FA): The Interconnection frequency measured in Hertz (Hz).

Actual Net Interchange (NIA): The algebraic sum of actual megawatt transfers across all Tie Lines, including Pseudo-Ties, to and from all Adjacent Balancing Authority areas within the same Interconnection. Actual megawatt transfers on asynchronous DC tie lines that are directly connected to another Interconnection are excluded from Actual Net Interchange.

Adequacy: 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.

Adjacent BalancingAuthority: A Balancing Authority whose Balancing Authority Area is interconnected with another Balancing Authority Area either directly or via a multi-party agreement or transmission tariff.

Adverse Reliability Impact: The impact of an event that results in frequency-related instability; unplanned tripping of load or generation; or uncontrolled separation or cascading outages that affects a widespread area of the Interconnection.

After the Fact: A time classification assigned to an RFI when the submittal time is greater than one hour after the start time of the RFI.

Agreement: A contract or arrangement, either written or verbal and sometimes enforceable by law.

Alternative Interpersonal Communication: Any Interpersonal Communication that is able to serve as a substitute for, and does not utilize the same infrastructure (medium) as, Interpersonal Communication used for day-to-day operation.

Altitude Correction Factor: A multiplier applied to specify distances, which adjusts the distances to account for the change in relative air density (RAD) due to altitude from the RAD used to determine the specified distance. Altitude correction factors apply to both minimum worker approach distances and to minimum vegetation clearance distances.

Ancillary Service: Those services that are necessary to support the transmission of capacity and energy from resources to loads while maintaining reliable operation of the Transmission Service Provider’s transmission system in accordance with good utility practice. (From FERC order 888-A. )

Anti-Aliasing Filter: An analog filter installed at a metering point to remove the high frequency components of the signal over the AGC sample period.

Area Control Error: The instantaneous difference between a Balancing Authority’s net actual and scheduled interchange, taking into account the effects of Frequency Bias, correction for meter error, and Automatic Time Error Correction (ATEC), if operating in the ATEC mode. ATEC is only applicable to Balancing Authorities in the Western Interconnection.

Area Interchange Methodology: The Area Interchange methodology is characterized by determination of incremental transfer capability via simulation, from which Total Transfer Capability (TTC) can be mathematically derived. Capacity Benefit Margin, Transmission Reliability Margin, and Existing Transmission Commitments are subtracted from the TTC, and Postbacks and counterflows are added, to derive Available Transfer Capability. Under the Area Interchange Methodology, TTC results are generally reported on an area to area basis.

Arranged Interchange: The state where a Request for Interchange (initial or revised) has been submitted for approval.

Attaining BalancingAuthority: A Balancing Authority bringing generation or load into its effective control boundaries through a Dynamic Transfer from the Native Balancing Authority.

Automatic Generation Control: A process designed and used to adjust a Balancing Authority Areas’ Demand and resources to help maintain the Reporting ACE in that of a Balancing Authority Area within the bounds required by applicable NERC Reliability Standards.

Automatic Time Error Correction (IATEC): • Y = Bi / BS.
• H = Number of hours used to payback primary inadvertent interchange energy. The value of H is set to 3.
B_i = Frequency Bias Setting for the Balancing Authority Area (MW / 0.1 Hz).
• B_S = Sum of the minimum Frequency Bias Settings for the Interconnection (MW / 0.1 Hz).
Primary Inadvertent Interchange (PII_hourly) is (1-Y) * (II_actual – Bi * ΔTE/6)
• II_actual is the hourly Inadvertent Interchange for the last hour.
ΔTE is the hourly change in system Time Error as distributed by the Interconnection time monitor,where: ΔTE = TE_end _hour – TE_begin _hour – TD_adj – (t)*(TE_offset)

Automatic Time Error Correction (IATEC): • TD_adj is the Reliability Coordinator adjustment for differences with Interconnection time monitor control center clocks.
• t is the number of minutes of manual Time Error Correction that occurred during the hour.
• TE_offset is 0.000 or +0.020 or -0.020.
• PII_accum is the Balancing Authority Area’s accumulated PIIhourly in MWh. An On-Peak and Off- Peak accumulation accounting is required,
where:

Automatic Time Error Correction (IATEC) continued below…: The addition of a component to the ACE equation for the Western Interconnection that modifies the control point for the purpose of continuously paying back Primary Inadvertent Interchange to correct accumulated time error. Automatic Time Error Correction is only applicable in the Western Interconnection.
when operating in Automatic Time error correction Mode.The absolute value of I_ATEC shall not
exceed L_max.
I_ATEC shall be zero when operating in any other AGC mode.
• L_max is the∗ maximum value allowed for I_ATEC set by each BA between 0.2*|B_i| and L10, 0.2*|B_i|≤ L_max ≤ L10 .
• L₁₀ =1.65
• ε10 is a constant derived from the targeted frequency bound. It is the targeted root-mean-square (RMS) value of ten-minute average frequency error based on frequency performance over a given year. The bound, ε 10, is the same for every Balancing Authority Area within an Interconnection.

Available Flowgate Capability: A measure of the flow capability remaining on a Flowgate for further commercial activity over and above already committed uses. It is defined as TFC less Existing Transmission Commitments (ETC), less a Capacity Benefit Margin, less a Transmission Reliability Margin, plus Postbacks, and plus counterflows.

Available Transfer Capability: A measure of the transfer capability remaining in the physical transmission network for further commercial activity over and above already committed uses. It is defined as Total Transfer Capability less Existing Transmission Commitments (including retail customer service), less a Capacity Benefit Margin, less a Transmission Reliability Margin, plus Postbacks, plus
counterflows.

Available TransferCapability Implementation Document: A document that describes the implementation of a methodology for calculating ATC or AFC, and provides information related to a Transmission Service Provider’s calculation of ATC or AFC.

BES Cyber Asset: A Cyber Asset that if rendered unavailable, degraded, or misused would, within 15 minutes of its required operation, misoperation, or non-operation, adversely impact one or more Facilities, systems, or equipment, which, if destroyed, degraded, or otherwise rendered unavailable when needed, would affect the reliable operation of the Bulk Electric System. Redundancy of affected Facilities, systems, and equipment shall not be considered when determining adverse impact. Each BES Cyber Asset is included in one or more BES Cyber Systems.

BES Cyber System: One or more BES Cyber Assets logically grouped by a responsible entity to perform one or more reliability tasks for a functional entity.

BES Cyber System Information: Information about the BES Cyber System that could be used to gain unauthorized access or pose a security threat to the BES Cyber System. BES Cyber System Information does not include individual pieces of information that by themselves do not pose a threat or could not be used to allow unauthorized access to BES Cyber Systems, such as, but not limited to, device names, individual IP addresses without context, ESP names, or policy statements. Examples of BES Cyber System Information may include, but are not limited to, security procedures or security information about BES Cyber Systems, Physical Access Control Systems, and Electronic Access Control or Monitoring Systems that is not publicly available and could be used to allow unauthorized access or unauthorized distribution; collections of network addresses; and network topology of the BES Cyber System.

Balancing Authority: The responsible entity that integrates resource plans ahead of time, maintains Demand and resource balance within a Balancing Authority Area, and supports Interconnection frequency in real time.

Balancing Authority Area: The collection of generation, transmission, and loads within the metered boundaries of the Balancing Authority. The Balancing Authority maintains load-resource balance within this area.

Balancing Contingency Event: Any single event described in Subsections (A), (B), or (C) below, or any series of such otherwise single events, with each separated from the next by one minute or less.
A. Sudden loss of generation:
a. Due to
i. unit tripping, or
ii. loss of generator Facility resulting in isolation of the
generator from the Bulk Electric System or from the responsible entity’s System, or
iii. sudden unplanned outage of transmission Facility;
b. And, that causes an unexpected change to the responsible entity’s ACE;
B. Sudden loss of an Import, due to forced outage of transmission equipment that causes an unexpected imbalance between generation and Demand on the Interconnection.
C. Sudden restoration of a Demand that was used as a resource that causes an unexpected change to the responsible entity’s ACE.

Base Load: The minimum amount of electric power delivered or required over a given period at a constant rate.

Blackstart Resource: A generating unit(s) and its associated set of equipment which has the ability to be started without support from the System or is designed to remain energized without connection to the remainder of the System, with the ability to energize a bus, meeting the Transmission Operator’s restoration plan needs for Real and Reactive Power capability, frequency and voltage control, and that has been included in the Transmission Operator’s restoration plan.

Block Dispatch: A set of dispatch rules such that given a specific amount of load to serve, an approximate generation dispatch can be determined. To accomplish this, the capacity of a given generator is segmented into loadable “blocks,” each of which is grouped and ordered relative to other blocks (based on characteristics including, but not limited to, efficiency, run of river or fuel supply considerations, and/or “must-run” status).

Bulk Electric System(continued below): Unless modified by the lists shown below, all Transmission Elements operated at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or higher. This does not include facilities used in the local distribution of electric energy.
Inclusions:
• I1 – Transformers with the primary terminal and at least one secondary terminal operated at 100 kV or higher unless excluded by application of Exclusion E1 or E3.
• I2 – Generating resource(s) including the generator terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above with:
a) Gross individual nameplate rating greater than 20 MVA. Or,
b) Gross plant/facility aggregate nameplate rating greater than 75 MVA.
• I3 – Blackstart Resources identified in the Transmission Operator’s restoration

Bulk Electric System(continued below): • I4 – Dispersed power producing resources that aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and that are connected through a system designed primarily for delivering such capacity to a common point of connection at a voltage of 100 kV or above. Thus, the facilities designated as BES are:
a) The individual resources, and
b) The system designed primarily for delivering capacity from the point where those resources aggregate to greater than 75 MVA to a common point of connection at a voltage of 100 kV or above.
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing Reactive Power that are connected at 100 kV or higher, or through a dedicated transformer with a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion I1 unless excluded by application of Exclusion E4.

Bulk Electric System(continued): Exclusions:
• E1 – Radial systems: A group of contiguous transmission Elements that emanates from a single point of connection of 100 kV or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusions I2, I3, or I4, with an aggregate capacity less than or equal to 75 MVA (gross nameplate rating). Or,
c) Where the radial system serves Load and includes generation resources, not identified in Inclusions I2, I3 or I4, with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note 1 – A normally open switching device between radial systems, as depicted on prints or one- line diagrams for example, does not affect this exclusion.
Note 2 – The presence of a contiguous loop, operated at a voltage level of 50 kV or less, between configurations being considered as radial systems, does not affect this exclusion.

Bulk Electric System(continued): E2 – A generating unit or multiple generating units on the customer’s side of the retail meter that serve all or part of the retail Load with electric energy if: (i) the net capacity provided to the BES does not exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided pursuant to a binding obligation with a Generator Owner or Generator Operator, or under terms approved by the applicable regulatory authority.

Bulk Electric System(continued): • E3 – Local networks (LN): A group of contiguous transmission Elements operated at less than 300 kV that distribute power to Load rather than transfer bulk power across the interconnected system. LN’s emanate from multiple points of connection at 100 kV or higher to improve the level of service to retail customers and not to accommodate bulk power transfer across the interconnected system. The LN is characterized by all of the following:
a) Limits on connected generation: The LN and its underlying Elements do not include generation resources identified in Inclusions I2, I3, or I4 and do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating);
b) Real Power flows only into the LN and the LN does not transfer energy originating outside the LN for delivery through the LN; and

Bulk Electric System(continued): c) Not part of a Flowgate or transfer path: The LN does not contain any part of a permanent Flowgate in the Eastern Interconnection, a major transfer path within the Western Interconnection, or a comparable monitored Facility in the ERCOT or Quebec Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).

• E4 – Reactive Power devices installed for the sole benefit of a retail customer(s).

Note – Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.

Bulk-Power System: Bulk-Power System:
(A) facilities and control systems necessary for operating an interconnected electric energy transmission network (or any portion thereof); and
electric energy from generation facilities needed to maintain transmission system reliability. The term does not include facilities used in the local distribution of electric energy. (Note that the terms “Bulk-Power System” or “Bulk Power System” shall have the same meaning.)

Burden: Operation of the Bulk Electric System that violates or is expected to violate a System Operating Limit or Interconnection Reliability Operating Limit in the Interconnection, or that violates any other NERC, Regional Reliability Organization, or local operating reliability standards or criteria.

Bus-tie Breaker: A circuit breaker that is positioned to connect two individual substation bus configurations.

CIP Exceptional Circumstance: A situation that involves or threatens to involve one or more of the following, or similar,conditions that impact safety or BES reliability: a risk of injury or death; a natural disaster; civil unrest; an imminent or existing hardware, software, or equipment failure; a Cyber Security Incident requiring emergency assistance; a response by emergency services; the enactment of a mutual assistance agreement; or an impediment of large scale workforce availability.

CIP Senior Manager: A single senior management official with overall authority and responsibility for leading and managing implementation of and continuing adherence to the requirements within the NERC CIP Standards, CIP-002 through CIP-011.

California ISO (CAISO): The California Independent System Operator (ISO) maintains reliability on one of the largest and most modern power grids in the world, and operates a transparent, accessible wholesale energy market.

Capacity Benefit Margin: The amount of firm transmission transfer capability preserved by the transmission provider for Load-Serving Entities (LSEs), whose loads are located on that Transmission Service Provider’s system, to enable access by the LSEs to generation from interconnected systems to meet generation reliability requirements. Preservation of CBM for an LSE allows that entity to reduce its installed generating capacity below that which may otherwise have been necessary without interconnections to meet its generation reliability requirements. The transmission transfer

Capacity Benefit Margin Implementation Document: A document that describes the implementation of a Capacity Benefit Margin methodology.

Capacity Emergency: A capacity emergency exists when a Balancing Authority Area’s operating capacity, plus firm purchases from other systems, to the extent available or limited by transfer capability, is inadequate to meet its demand plus its regulating requirements.

Cascading: The uncontrolled successive loss of System Elements triggered by an incident at any location. Cascading results in widespread electric service interruption that cannot be restrained from sequentially spreading beyond an area predetermined by studies.

Clock Hour: The 60-minute period ending at :00. All surveys, measurements, and reports are based on Clock Hour periods unless specifically noted.

Cogeneration: Production of electricity from steam, heat, or other forms of energy produced as a by-product of another process.

Compliance Monitor: The entity that monitors, reviews, and ensures compliance of responsible entities with reliability standards.

Composite Confirmed Interchange: The energy profile (including non-default ramp) throughout a given time period, based on the aggregate of all Confirmed Interchange occurring in that time period.

Composite Protection System: The total complement of Protection System(s) that function collectively to protect an Element. Backup protection provided by a different Element’s Protection System(s) is excluded.

Confirmed Interchange: The state where no party has denied and all required parties have approved the Arranged Interchange.

Congestion Management Report: A report that the Interchange Distribution Calculator issues when a Reliability Coordinator initiates the Transmission Loading Relief procedure. This report identifies the transactions and native and network load curtailments that must be initiated to achieve the loading relief requested by the initiating Reliability Coordinator.

Consequential Load Loss: All Load that is no longer served by the Transmission system as a result of Transmission Facilities being removed from service by a Protection System operation designed to isolate the fault.

Constrained Facility: A transmission facility (line, transformer, breaker, etc.) that is approaching, is at, or is beyond its System Operating Limit or Interconnection Reliability Operating Limit.

Contact Path: An agreed upon electrical path for the continuous flow of electrical power between the parties of an Interchange Transaction.

Contingency: The unexpected failure or outage of a system component, such as a generator, transmission line, circuit breaker, switch or other electrical element.

Contingency Event Recovery Period: A period that begins at the time that the resource output begins to decline within the first one-minute interval of a Reportable Balancing Contingency Event, and extends for fifteen minutes thereafter.

Contingency Reserve: The provision of capacity that may be deployed by the Balancing Authority to respond to a Balancing Contingency Event and other contingency requirements (such as Energy Emergency Alerts as specified in the associated EOP standard). A Balancing Authority may include in its restoration of Contingency Reserve readiness to reduce Firm Demand and include it if, and only if, the Balancing Authority:
• is experiencing a Reliability Coordinator declared Energy Emergency Alert level, and is utilizing its Contingency Reserve to mitigate an operating emergency in accordance with its emergency Operating Plan.
• is utilizing its Contingency Reserve to mitigate an operating emergency in accordance with its emergency Operating Plan.

Contingency Reserve Restoration Period: A period not exceeding 90 minutes following the end of the Contingency Event Recovery Period.

Control Center: One or more facilities hosting operating personnel that monitor and control the Bulk Electric System (BES) in real-time to perform the reliability tasks, including their associated data centers, of: 1) a Reliability Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for transmission Facilities at two or more locations, or 4) a Generator Operator for generation Facilities at two or more locations.

Control Performance Standard: The reliability standard that sets the limits of a Balancing Authority’s Area Control Error over a specified time period.

Corrective Action Plan: A list of actions and an associated timetable for implementation to remedy a specific problem.

Cranking Path: A portion of the electric system that can be isolated and then energized to deliver electric power from a generation source to enable the startup of one or more other generating units.

Curtailment: A reduction in the scheduled capacity or energy delivery of an Interchange Transaction.

Curtailment Threshold: The minimum Transfer Distribution Factor which, if exceeded, will subject an Interchange Transaction to curtailment to relieve a transmission facility constraint.

Cyber Assets: Programmable electronic devices, including the hardware, software, and data in those devices.

Cyber Security Incident: A malicious act or suspicious event that:
– For a high or medium impact BES Cyber System, compromises or attempts to compromise (1) an Electronic Security Perimeter, (2) a Physical Security Perimeter, or (3) an Electronic Access Control or Monitoring System; or
– Disrupts or attempts to disrupt the operation of a BES Cyber System.

Delayed Fault Clearing: Fault clearing consistent with correct operation of a breaker failure protection system and its associated breakers, or of a backup protection system with an intentional time delay.

Demand: 1. The rate at which electric energy is delivered to or by a system or part of a system, generally
expressed in kilowatts or megawatts, at a given instant or averaged over any designated interval of time.
2. The rate at which energy is being used by the customer.

Demand-Side Management: All activities or programs undertaken by any applicable entity to achieve a reduction in Demand.

Dial-up Connectivity: A data communication link that is established when the communication equipment dials a phone number and negotiates a connection with the equipment on the other end of the link.

Direct Control Load Management: Demand-Side Management that is under the direct control of the system operator. DCLM may control the electric supply to individual appliances or equipment on customer premises. DCLM as defined here does not include Interruptible Demand.

Dispatch Order: A set of dispatch rules such that given a specific amount of load to serve, an approximate generation dispatch can be determined. To accomplish this, each generator is ranked by priority.

Dispersed Load by Substations: Substation load information configured to represent a system for power flow or system dynamics modeling purposes, or both.

Distribution Factor: The portion of an Interchange Transaction, typically expressed in per unit that flows across a transmission facility (Flowgate).

Distribution Provider: Provides and operates the “wires” between the transmission system and the end-use customer. For those end-use customers who are served at transmission voltages, the Transmission Owner also serves as the Distribution Provider. Thus, the Distribution Provider is not defined by a specific voltage, but rather as performing the distribution function at any voltage.

Disturbance: 1. An unplanned event that produces an abnormal system condition.
2. Any perturbation to the electric system.
3. The unexpected change in ACE that is caused by the sudden failure of generation or interruption of load.

Disturbance Control Standard: The reliability standard that sets the time limit following a Disturbance within which a Balancing Authority must return its Area Control Error to within a specified range.

Disturbance Monitoring Equipment: Devices capable of monitoring and recording system data pertaining to a Disturbance. Such devices include the following categories of recorders* :
• Sequence of event recorders which record equipment response to the event
• Fault recorders, which record actual waveform data replicating the system primary voltages and currents. This may include protective relays.
• Dynamic Disturbance Recorders (DDRs), which record incidents that portray power system behavior during dynamic events such as low-frequency (0.1 Hz – 3 Hz) oscillations and abnormal frequency or voltage excursions
*Phasor Measurement Units and any other equipment that meets the functional requirements

Dynamic InterchangeSchedule or Dynamic Schedule: A time-varying energy transfer that is updated in Real-time and included in the Scheduled Net Interchange (NIS) term in the same manner as an Interchange Schedule in the affected Balancing Authorities’ control ACE equations (or alternate control processes).

Dynamic Transfer: The provision of the real-time monitoring, telemetering, computer software, hardware, communications, engineering, energy accounting (including inadvertent interchange), and administration required to electronically move all or a portion of the real energy services associated with a generator or load out of one Balancing Authority Area into another.

Economic Dispatch: The allocation of demand to individual generating units on line to effect the most economical production of electricity.

Electric Reliability Council of Texas (ERCOT): The Electric Reliability Council of Texas (ERCOT) manages the flow of electric power to more than 26 million Texas customers — representing about 90 percent of the state’s electric load.

Electrical Energy: The generation or use of electric power by a device over a period of time, expressed in kilowatthours (kWh), megawatthours (MWh), or gigawatthours (GWh).

Electronic Access Control or Monitoring Systems: Cyber Assets that perform electronic access control or electronic access monitoring of the Electronic Security Perimeter(s) or BES Cyber Systems. This includes Intermediate Systems.

Electronic Access Point: A Cyber Asset interface on an Electronic Security Perimeter that allows routable communication between Cyber Assets outside an Electronic Security Perimeter and Cyber Assets inside an Electronic Security Perimeter.

Electronic SecurityPerimeter: The logical border surrounding a network to which BES Cyber Systems are connected using a routable protocol.

Element: Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit breaker, bus section, or transmission line. An Element may be comprised of one or more components.

Emergency Rating: The rating as defined by the equipment owner that specifies the level of electrical loading or output, usually expressed in megawatts (MW) or Mvar or other appropriate units, that a system, facility, or element can support, produce, or withstand for a finite period. The rating assumes acceptable loss of equipment life or other physical or safety limitations for the equipment involved.

Emergency Request for Interchange: Request for Interchange to be initiated for Emergency or Energy Emergency conditions.

Emergency or BES Emergency: Any abnormal system condition that requires automatic or immediate manual action to prevent or limit the failure of transmission facilities or generation supply that could adversely affect the reliability of the Bulk Electric System.

Energy Emergency: A condition when a Load-Serving Entity or Balancing Authority has exhausted all other resource options and can no longer meet its expected Load obligations.

Equipment Rating: The maximum and minimum voltage, current, frequency, real and reactive power flows on individual equipment under steady state, short-circuit and transient conditions, as permitted or assigned by the equipment owner.

Existing Transmission Commitments: Committed uses of a Transmission Service Provider’s Transmission system considered when determining ATC or AFC.

External Routable Connectivity: The ability to access a BES Cyber System from a Cyber Asset that is outside of its associated Electronic Security Perimeter via a bi-directional routable protocol connection.

Facility: A set of electrical equipment that operates as a single Bulk Electric System Element (e.g., a line, a generator, a shunt compensator, transformer, etc.)

Facility Rating: The maximum or minimum voltage, current, frequency, or real or reactive power flow through a facility that does not violate the applicable equipment rating of any equipment comprising the facility.

Fault: An event occurring on an electric system such as a short circuit, a broken wire, or an intermittent connection.

Fire Risk: The likelihood that a fire will ignite or spread in a particular geographic area

Firm Demand: That portion of the Demand that a power supplier is obligated to provide except when system reliability is threatened or during emergency conditions.

Firm Transmission Service: The highest quality (priority) service offered to customers under a filed rate schedule that anticipates no planned interruption.

Flashover: An electrical discharge through air around or over the surface of insulation, between objects of different potential, caused by placing a voltage across the air space that results in the ionization of the air space.

Flowgate: 1.) A portion of the Transmission system through which the Interchange Distribution Calculator calculates the power flow from Interchange Transactions.
2.) A mathematical construct, comprised of one or more monitored transmission Facilities and optionally one or more contingency Facilities, used to analyze the impact of power flows upon the Bulk Electric System.

Flowgate Methodology: The Flowgate methodology is characterized by identification of key Facilities as Flowgates. Total Flowgate Capabilities are determined based on Facility Ratings and voltage and stability limits.
The impacts of Existing Transmission Commitments (ETCs) are determined by simulation. The impacts of ETC, Capacity Benefit Margin (CBM) and Transmission Reliability Margin (TRM) are subtracted from the Total Flowgate Capability, and Postbacks and counterflows are added, to determine the Available Flowgate Capability (AFC) value for that Flowgate. AFCs can be used to determine Available Transfer Capability (ATC).

Forced Outage: 1. The removal from service availability of a generating unit, transmission line, or other facility for emergency reasons.
2. The condition in which the equipment is unavailable due to unanticipated failure.

Frequency Bias: A value, usually expressed in megawatts per 0.1 Hertz (MW/0.1 Hz), associated with a Balancing Authority Area that approximates the Balancing Authority Area’s response to Interconnection frequency error.

Frequency Bias Setting: A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s inverse Frequency Response contribution to the Interconnection, and discourage response withdrawal through secondary control systems.

Frequency Deviation: A change in Interconnection frequency.

Frequency Error: The difference between the actual and scheduled frequency. (F_A – F_S)

Frequency Regulation: The ability of a Balancing Authority to help the Interconnection maintain Scheduled Frequency. This assistance can include both turbine governor response and Automatic Generation Control.

Frequency Response: (Equipment) The ability of a system or elements of the system to react or respond to a change in system frequency. (System) The sum of the change in demand, plus the change in generation, divided by the change in frequency, expressed in megawatts per 0.1 Hertz (MW/0.1 Hz).

Frequency Response Measure: The median of all the Frequency Response observations reported annually by Balancing Authorities or Frequency Response Sharing Groups for frequency events specified by the ERO. This will be calculated as MW/0.1Hz.

Frequency Response Obligation: The Balancing Authority’s share of the required Frequency Response needed for the reliable
operation of an Interconnection. This will be calculated as MW/0.1Hz

Frequency Response Sharing Group: A group whose members consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the sum of the Frequency Response Obligations of its members.

Generation Capability Import Requirement: The amount of generation capability from external sources identified by a Load-Serving Entity (LSE) or Resource Planner (RP) to meet its generation reliability or resource adequacy requirements as an alternative to internal resources

Generator Operator: The entity that operates generating Facility(ies) and performs the functions of supplying energy and Interconnected Operations Services

Generator Owner: Entity that owns and maintains generating Facility(ies).

Generator Shift Factor: A factor to be applied to a generator’s expected change in output to determine the amount of flow contribution that change in output will impose on an identified transmission facility or Flowgate.

Generator-to-Load Distribution Factor: The algebraic sum of a Generator Shift Factor and a Load Shift Factor to determine the total impact of an Interchange Transaction on an identified transmission facility or Flowgate.

Geomagnetic Disturbance Vulnerability Assessment or GMD Vulnerability Assessment: Documented evaluation of potential susceptibility to voltage collapse, Cascading, or localized damage of equipment due to geomagnetic disturbances.

Host Balancing Authority: 1. A Balancing Authority that confirms and implements Interchange Transactions for a Purchasing Selling Entity that operates generation or serves customers directly within the Balancing Authority’s metered boundaries.
2. The Balancing Authority within whose metered boundaries a jointly owned unit is physically located.

Hourly Value: Data measured on a Clock Hour basis.

Implemented Interchange: The state where the Balancing Authority enters the Confirmed Interchange into its Area Control Error equation.

Inadvertent Interchange: The difference between the Balancing Authority’s Net Actual Interchange and Net Scheduled Interchange. (IA – IS)

Independent Power Producer: Any entity that owns or operates an electricity generating facility that is not included in an electric utility’s rate base. This term includes, but is not limited to, cogenerators and small power producers and all other nonutility electricity producers, such as exempt wholesale generators, who sell electricity.

Interactive Remote Access: User-initiated access by a person employing a remote access client or other remote access technology using a routable protocol. Remote access originates from a Cyber Asset that is not an Intermediate System and not located within any of the Responsible Entity’s Electronic Security Perimeter(s) or at a defined Electronic Access Point (EAP). Remote access may be initiated from: 1) Cyber Assets used or owned by the Responsible Entity, 2) Cyber Assets used or owned by employees, and 3) Cyber Assets used or owned by vendors, contractors, or consultants. Interactive remote access does not include system-to-system process

Interchange: communications Energy transfers that cross Balancing Authority boundaries.

Interchange Authority: The responsible entity that authorizes the implementation of valid and balanced Interchange Schedules between Balancing Authority Areas, and ensures communication of Interchange information for reliability assessment purposes.

Interchange Distribution Calculator: The mechanism used by Reliability Coordinators in the Eastern Interconnection to calculate the distribution of Interchange Transactions over specific Flowgates. It includes a database of all Interchange Transactions and a matrix of the Distribution Factors for the Eastern Interconnection

Interchange Meter Error(IME): A term used in the Reporting ACE calculation to compensate for data or equipment errors affecting any other components of the Reporting ACE calculation.

Interchange Schedule: An agreed-upon Interchange Transaction size (megawatts), start and end time, beginning and ending ramp times and rate, and type required for delivery and receipt of power and energy between the Source and Sink Balancing Authorities involved in the transaction.

Interchange Transaction: An agreement to transfer energy from a seller to a buyer that crosses one or more Balancing Authority Area boundaries.

Interchange Transaction Tag or Tag: The details of an Interchange Transaction required for its physical implementation.

InterconnectedOperations Service: A service (exclusive of basic energy and Transmission Services) that is required to support the Reliable Operation of interconnected Bulk Electric Systems.

Interconnection: A geographic area in which the operation of Bulk Power System components is synchronized such that the failure of one or more of such components may adversely affect the ability of the operators of other components within the system to maintain Reliable Operation of the Facilities within their control. When capitalized, any one of the four major electric system networks in North America: Eastern, Western, ERCOT and Quebec.

Interconnection Reliability Operating Limit: A System Operating Limit that, if violated, could lead to instability, uncontrolled separation, or Cascading outages that adversely impact the reliability of the Bulk Electric System.

Interconnection Reliability Operating Limit Tv: The maximum time that an Interconnection Reliability Operating Limit can be violated before the risk to the interconnection or other Reliability Coordinator Area(s) becomes greater than acceptable. Each Interconnection Reliability Operating Limit’s T_v shall be less than or equal to 30 minutes.

Intermediate Balancing Authority: A Balancing Authority on the scheduling path of an Interchange Transaction other than the Source Balancing Authority and Sink Balancing Authority.

Intermediate System: A Cyber Asset or collection of Cyber Assets performing access control to restrict Interactive Remote Access to only authorized users. The Intermediate System must not be located inside the Electronic Security Perimeter.

Interpersonal Communication: Any medium that allows two or more individuals to interact, consult, or exchange information.

Interruptible Load or Interruptible Demand: Demand that the end-use customer makes available to its Load-Serving Entity via contract or agreement for curtailment.

Joint Control: Automatic Generation Control of jointly owned units by two or more Balancing Authorities.

Limiting Element: The element that is 1. )Either operating at its appropriate rating, or 2,) Would be following the limiting contingency. Thus, the Limiting Element establishes a system limit.

Load: An end-use device or customer that receives power from the electric system.

Load Shift Factor: A factor to be applied to a load’s expected change in demand to determine the amount of flow contribution that change in demand will impose on an identified transmission facility or monitored Flowgate.

Load-Serving Entity: Secures energy and Transmission Service (and related Interconnected Operations Services) to serve the electrical demand and energy requirements of its end-use customers.

Long-Term Transmission Planning Horizon: Transmission planning period that covers years six through ten or beyond when required to accommodate any known longer lead time projects that may take longer than ten years to complete.

Market Flow: The total amount of power flowing across a specified Facility or set of Facilities due to a market dispatch of generation internal to the market to serve load internal to the market.

Midwest Reliability Organization (MRO): As part of the ERO Enterprise, MRO operates as a cross-border Regional Entity headquartered in Saint Paul, Minnesota. The MRO region spans the provinces of Saskatchewan and Manitoba, and all or parts of the states of Arkansas, Illinois, Iowa, Kansas, Louisiana, Michigan, Minnesota, Missouri, Montana, Nebraska, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, and Wisconsin.

Minimum Vegetation Clearance Distance: The calculated minimum distance stated in feet (meters) to prevent flash-over between conductors and vegetation, for various altitudes and operating voltages.

Misoperation: The failure of a Composite Protection System to operate as intended for protection purposes. Any of the following is a Misoperation:

1. Failure to Trip – During Fault – A failure of a Composite Protection System to operate for a Fault condition for which it is designed. The failure of a Protection System component is not a Misoperation as long as the performance of the Composite Protection System is correct.
2. Failure to Trip – Other Than Fault – A failure of a Composite Protection System to operate for a non-Fault condition for which it is designed, such as a power swing, undervoltage, overexcitation, or loss of excitation. The failure of a Protection System component is not a Misoperation as long as the performance of the Composite Protection System is correct.
3. Slow Trip – During Fault – A Composite Protection System operation that is slower than required for a Fault condition if the duration of its operating time resulted in the operation of at least one other Element’s Composite Protection System.
4. Slow Trip – Other Than Fault – A Composite Protection System operation that is slower than required for a non-Fault condition, such as a power swing, undervoltage, overexcitation, or loss of excitation, if the duration of its operating time resulted in the operation of at least one other Element’s Composite Protection System.
5. Unnecessary Trip – During Fault – An unnecessary Composite Protection System operation for a Fault condition on another Element.
6. Unnecessary Trip – Other Than Fault – An unnecessary Composite Protection System operation for a non-Fault condition. A Composite Protection System operation that is caused by personnel during on-site maintenance, testing, inspection, construction, or commissioning activities is not a Misoperation.

Most Severe Single Contingency: The Balancing Contingency Event, due to a single contingency identified using system models maintained within the Reserve Sharing Group (RSG) or a Balancing Authority’s area that is not part of a Reserve Sharing Group, that would result in the greatest loss (measured in MW) of resource output used by the RSG or a Balancing Authority that is not participating as a member of a RSG at the time of the event to meet Firm Demand and export
obligation (excluding export obligation for which Contingency Reserve obligations are being met by the Sink Balancing Authority).

Native Balancing Authority: A Balancing Authority from which a portion of its physically interconnected generation and/or load is transferred from its effective control boundaries to the Attaining Balancing Authority through a Dynamic Transfer.

Native Load: The end-use customers that the Load-Serving Entity is obligated to serve.

Near-Term Transmission Planning Horizon: The transmission planning period that covers Year One through five.

Net Actual Interchange: The algebraic sum of all metered interchange over all interconnections between two physically Adjacent Balancing Authority Areas.

Net Energy for Load: Net Balancing Authority Area generation, plus energy received from other Balancing Authority Areas, less energy delivered to Balancing Authority Areas through interchange. It includes Balancing Authority Area losses but excludes energy required for storage at energy storage facilities.

Net Interchange Schedule: The algebraic sum of all Interchange Schedules with each Adjacent Balancing Authority.

Net Scheduled Interchange: The algebraic sum of all Interchange Schedules across a given path or between Balancing Authorities for a given period or instant in time.

Network Integration Transmission Service: Service that allows an electric transmission customer to integrate, plan, economically dispatch and regulate its network reserves in a manner comparable to that in which the Transmission Owner serves Native Load customers.

Non-Consequential Load Loss: Non-Interruptible Load loss that does not include: (1) Consequential Load Loss, (2) the response of voltage sensitive Load, or (3) Load that is disconnected from the System by end-user equipment.

Non-Firm Transmission Service: Transmission service that is reserved on an as-available basis and is subject to curtailment or interruption

Non-Spinning Reserve: 1. That generating reserve not connected to the system but capable of serving demand within a specified time.
2. Interruptible load that can be removed from the system in a specified time.

Normal Clearing: A protection system operates as designed and the fault is cleared in the time normally expected with proper functioning of the installed protection systems.

Normal Rating: The rating as defined by the equipment owner that specifies the level of electrical loading, usually expressed in megawatts (MW) or other appropriate units that a system, facility, or element can support or withstand through the daily demand cycles without loss of equipment life.

Northeast Power Coordinating Council (NPCC): Northeast Power Coordinating Council, Inc. (NPCC) is a not-for-profit corporation in the state of New York responsible for promoting and enhancing the reliability of the international, interconnected bulk power system in Northeastern North America.

Nuclear Plant Generator Operator: Any Generator Operator or Generator Owner that is a Nuclear Plant Licensee responsible for operation of a nuclear facility licensed to produce commercial power.

Nuclear Plant Interface Requirements: The requirements based on NPLRs and Bulk Electric System requirements that have been mutually agreed to by the Nuclear Plant Generator Operator and the applicable Transmission Entities.

Nuclear Plant Licensing Requirements: Requirements included in the design basis of the nuclear plant and statutorily mandated for the operation of the plant, including nuclear power plant licensing requirements for:
1) Off-site power supply to enable safe shutdown of the plant during an electric system or plant event; and
2) Avoiding preventable challenges to nuclear safety as a result of an electric system disturbance, transient, or condition.

Nuclear Plant Off-site Power Supply (Off-site Power): The electric power supply provided from the electric system to the nuclear power plant distribution system as required per the nuclear power plant license.

Off-Peak: Those hours or other periods defined by NAESB business practices, contract, agreements, or guides as periods of lower electrical demand.

On-Peak: Those hours or other periods defined by NAESB business practices, contract, agreements, or guides as periods of higher electrical demand.

Open Access Same Time Information Service: An electronic posting system that the Transmission Service Provider maintains for transmission access data and that allows all transmission customers to view the data simultaneously.

Open Access Transmission Tariff: Electronic transmission tariff accepted by the U.S. Federal Energy Regulatory Commission requiring the Transmission Service Provider to furnish to all shippers with non-discriminating service comparable to that provided by Transmission Owners to themselves.

Operating Instruction: A command by operating personnel responsible for the Real-time operation of the interconnected Bulk Electric System to change or preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric System. (A discussion of general information and of potential options or alternatives to resolve Bulk Electric System operating concerns is not a command and is not considered an Operating Instruction.)

Operating Plan: A document that identifies a group of activities that may be used to achieve some goal. An Operating Plan may contain Operating Procedures and Operating Processes. A company- specific system restoration plan that includes an Operating Procedure for black-starting units, Operating Processes for communicating restoration progress with other entities, etc., is an example of an Operating Plan.

Operating Procedure: A document that identifies specific steps or tasks that should be taken by one or more specific operating positions to achieve specific operating goal(s). The steps in an Operating Procedure should be followed in the order in which they are presented, and should be performed by the position(s) identified. A document that lists the specific steps for a system operator to take in removing a specific transmission line from service is an example of an Operating Procedure.

Operating Process: A document that identifies general steps for achieving a generic operating goal. An Operating Process includes steps with options that may be selected depending upon Real-time conditions. A guideline for controlling high voltage is an example of an Operating Process.

Operating Reserve: That capability above firm system demand required to provide for regulation, load forecasting error, equipment forced and scheduled outages and local area protection. It consists of spinning and non-spinning reserve.

Operating Reserve – Spinning: The portion of Operating Reserve consisting of:
• Generation synchronized to the system and fully available to serve load within the Disturbance Recovery Period following the contingency event; or
• Load fully removable from the system within the Disturbance Recovery Period following the contingency event.

Operating Reserve – Supplemental: The portion of Operating Reserve consisting of:
• Generation (synchronized or capable of being synchronized to the system) that is fully available to serve load within the Disturbance Recovery Period following the contingency event; or
Load fully removable from the system within the Disturbance Recovery Period following the contingency event.

Operating Voltage: The voltage level by which an electrical system is designated and to which certain operating characteristics of the system are related; also, the effective (root-mean-square) potential difference between any two conductors or between a conductor and the ground. The actual voltage of the circuit may vary somewhat above or below this value.

Operational Planning Analysis: An evaluation of projected system conditions to assess anticipated (pre-Contingency) and potential (post-Contingency) conditions for next-day operations. The evaluation shall reflect applicable inputs including, but not limited to: load forecasts; generation output levels; Interchange; known Protection System and Remedial Action Scheme status or degradation, functions, and limitations; Transmission outages; generator outages; Facility Ratings; and identified phase angle and equipment limitations.
(Operational Planning Analysis may be provided through internal systems or through third-party services.)

Operational Planning Analysis: An evaluation of projected system conditions to assess anticipated (pre-Contingency) and potential (post-Contingency) conditions for next-day operations. The evaluation shall reflect applicable inputs including, but not limited to, load forecasts; generation output levels; Interchange; known Protection System and Special Protection System status or degradation; Transmission outages; generator outages; Facility Ratings; and identified phase angle and equipment limitations. (Operational Planning Analysis may be provided through internal systems or through third-party services )

Operations Support Personnel: Individuals who perform current day or next day outage coordination or assessments, or who determine SOLs, IROLs, or operating nomograms,1 in direct support of Real-time operations of the Bulk Electric System.

Outage Transfer Distribution Factor: In the post-contingency configuration of a system under study, the electric Power Transfer Distribution Factor (PTDF) with one or more system Facilities removed from service (outaged).

Overlap Regulation Service: A method of providing regulation service in which the Balancing Authority providing the regulation service incorporates another Balancing Authority’s actual interchange, frequency response, and schedules into providing Balancing Authority’s AGC/ACE equation.

Participation Factors: A set of dispatch rules such that given a specific amount of load to serve, an approximate generation dispatch can be determined. To accomplish this, generators are assigned a percentage that they will contribute to serve load.

Peak Demand: 1. The highest hourly integrated Net Energy For Load within a Balancing Authority Area occurring within a given period (e.g., day, month, season, or year).
2. The highest instantaneous demand within the Balancing Authority Area.

Performance-: The time period that the entity being assessed must operate without any violations to reset the level of non compliance to zero.

Physical Access Control Systems: Cyber Assets that control, alert, or log access to the Physical Security Perimeter(s), exclusive of locally mounted hardware or devices at the Physical Security Perimeter such as motion sensors, electronic lock control mechanisms, and badge readers.

Physical Security Perimeter: The physical border surrounding locations in which BES Cyber Assets, BES Cyber Systems, or Electronic Access Control or Monitoring Systems reside, and for which access is controlled.

Planning Assessment: Documented evaluation of future Transmission System performance and Corrective Action Plans to remedy identified deficiencies.

Planning Authority: The responsible entity that coordinates and integrates transmission Facilities and service plans, resource plans, and Protection Systems.

Planning Coordinator: See Planning Authority.

Point of Delivery: A location that the Transmission Service Provider specifies on its transmission system where an Interchange Transaction leaves or a Load-Serving Entity receives its energy.

Point of Receipt: A location that the Transmission Service Provider specifies on its transmission system where an Interchange Transaction enters or a generator delivers its output.

Point to Point Transmission Service: The reservation and transmission of capacity and energy on either a firm or non-firm basis from the Point(s) of Receipt to the Point(s) of Delivery.

Power Transfer Distribution Factor: In the pre-contingency configuration of a system under study, a measure of the responsiveness or change in electrical loadings on transmission system Facilities due to a change in electric power transfer from one area to another, expressed in percent (up to 100%) of the change in power transfer

Pre-Reporting Contingency Event ACE Value: The average value of Reporting ACE, or Reserve Sharing Group Reporting ACE when applicable, in the 16-second interval immediately prior to the start of the Contingency Event Recovery Period based on EMS scan rate data.

Pro Forma Tariff: Usually refers to the standard OATT and/or associated transmission rights mandated by the U.S.
Federal Energy Regulatory Commission Order No. 888.

Protected Cyber Assets: One or more Cyber Assets connected using a routable protocol within or on an Electronic Security Perimeter that is not part of the highest impact BES Cyber System within the same Electronic Security Perimeter. The impact rating of Protected Cyber Assets is equal to the highest rated BES Cyber System in the same ESP.

Protection System: Protection System –
• Protective relays which respond to electrical quantities,
• Communications systems necessary for correct operation of protective functions
• Voltage and current sensing devices providing inputs to protective relays,
• Station dc supply associated with protective functions (including station batteries, battery chargers, and non-battery-based dc supply), and
Control circuitry associated with protective functions through the trip coil(s) of the circuit breakers or other interrupting devices.

Protection System Coordination Study: An analysis to determine whether Protection Systems operate in the intended sequence during Faults.

Protection System Maintenance Program (PRC-005-6): An ongoing program by which Protection System,
Automatic Reclosing, and Sudden Pressure Relaying Components are kept in working order and proper
operation of malfunctioning Components is restored. A maintenance program for a specific Component includes one or more of the following activities:
• Verify — Determine that the Component is functioning correctly.
• Monitor — Observe the routine in-service operation of the Component.
• Test — Apply signals to a Component to observe functional performance or output behavior, or to diagnose problems.
• Inspect — Examine for signs of Component failure, reduced performance or degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring element to meet the intended performance requirement.

Pseudo-Tie: A time-varying energy transfer that is updated in Real-time and included in the Actual Net Interchange term (NIA) in the same manner as a Tie Line in the affected Balancing Authorities’ Reporting ACE equation (or alternate control processes).

Public Utility Commission of Texas (PUCT): The Public Utility Commission of Texas (PUCT) is the state agency responsible for economic regulation of Texas’ electric, telecommunication, and water and wastewater utilities.

Purchasing-Selling Entity: The entity that purchases or sells, and takes title to, energy, capacity, and Interconnected Operations Services. Purchasing-Selling Entities may be affiliated or unaffiliated merchants and may or may not own generating facilities.

Ramp Rate or Ramp: (Schedule) The rate, expressed in megawatts per minute, at which the interchange schedule is attained during the ramp period.
(Generator) The rate, expressed in megawatts per minute, that a generator changes its output.

Rated Electrical Operating Conditions: The specified or reasonably anticipated conditions under which the electrical system or an individual electrical circuit is intend/designed to operate

Rated System Path Methodology: The Rated System Path Methodology is characterized by an initial Total Transfer Capability (TTC), determined via simulation. Capacity Benefit Margin, Transmission Reliability Margin, and Existing Transmission Commitments are subtracted from TTC, and Postbacks and counterflows are added as applicable, to derive Available Transfer Capability. Under the Rated System Path Methodology, TTC results are generally reported as specific transmission path capabilities.

Rating: The operational limits of a transmission system element under a set of specified conditions.

Reactive Power: The portion of electricity that establishes and sustains the electric and magnetic fields of alternating-current equipment. Reactive Power must be supplied to most types of magnetic equipment, such as motors and transformers. It also must supply the reactive losses on transmission facilities. Reactive Power is provided by generators, synchronous condensers, or electrostatic equipment such as capacitors and directly influences electric system voltage. It is usually expressed in kilovars (kvar) or megavars (Mvar).

Real Power: The portion of electricity that supplies energy to the Load.

Real-time: Present time as opposed to future time. (From Interconnection Reliability Operating Limits standard.)

Real-time Assessment: An evaluation of system conditions using Real-time data to assess existing (pre-Contingency) and potential (post-Contingency) operating conditions. The assessment shall reflect applicable inputs including, but not limited to: load; generation output levels; known Protection System and Remedial Action Scheme status or degradation, functions, and limitations; Transmission outages; generator outages; Interchange; Facility Ratings; and identified phase angle and equipment limitations. (Realtime Assessment may be provided through internal systems or through third-party services.)

Receiving Balancing Authority: The Balancing Authority importing the Interchange.

Regional Reliability Organization: 1. An entity that ensures that a defined area of the Bulk Electric System is reliable, adequate
and secure.
2. A member of the North American Electric Reliability Council. The Regional Reliability Organization can serve as the Compliance Monitor.

Regional Reliability Plan: The plan that specifies the Reliability Coordinators and Balancing Authorities within the Regional Reliability Organization, and explains how reliability coordination will be accomplished.

Regulating Reserve: An amount of reserve responsive to Automatic Generation Control, which is sufficient to provide normal regulating margin.

Regulation Reserve Sharing Group: A group whose members consist of two or more Balancing
Authorities that collectively maintain, allocate, and supply the Regulating Reserve required for all member Balancing Authorities to use in meeting applicable regulating standards.

Regulation Service: The process whereby one Balancing Authority contracts to provide corrective response to all or a portion of the ACE of another Balancing Authority. The Balancing Authority providing the response assumes the obligation of meeting all applicable control criteria as specified by NERC for itself and the Balancing Authority for which it is providing the Regulation Service.

Reliability Adjustment Arranged Interchange: A request to modify a Confirmed Interchange or Implemented Interchange for reliability purposes.

Reliability Adjustment RFI: Request to modify an Implemented Interchange Schedule for reliability purposes.

Reliability Coordinator: The entity that is the highest level of authority who is responsible for the Reliable Operation of the Bulk Electric System, has the Wide Area view of the Bulk Electric System, and has the operating tools, processes and procedures, including the authority to prevent or mitigate emergency operating situations in both next-day analysis and real-time operations. The Reliability Coordinator has the purview that is broad enough to enable the calculation of Interconnection Reliability Operating Limits, which may be based on the operating parameters of transmission systems beyond any Transmission Operator’s vision.

Reliability Coordinator Area: The collection of generation, transmission, and loads within the boundaries of the Reliability Coordinator. Its boundary coincides with one or more Balancing Authority Areas.

Reliability Coordinator Information System: The system that Reliability Coordinators use to post messages and share operating information in real time.

Reliability Standard: A requirement, approved by the United States Federal Energy Regulatory Commission under Section 215 of the Federal Power Act, or approved or recognized by an applicable governmental authority in other jurisdictions, to provide for Reliable Operation of the Bulk-Power System. The term includes requirements for the operation of existing Bulk-Power System facilities, including cybersecurity protection, and the design of planned additions or modifications to such facilities to the extent necessary to provide for Reliable Operation of the Bulk-Power System, but the term does not include any requirement to enlarge such facilities or to construct new transmission capacity or generation capacity.

ReliabilityFirst Corporation (RFC): ReliabilityFirst (RF) is one of the six Federal Energy Regulatory Commission (Commission)-approved regional entities responsible for ensuring the reliability of the North American Bulk-Power System, pursuant to the Energy Policy Act of 2005.

Reliable Operation: Operating the elements of the [Bulk-Power System] within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a
cybersecurity incident, or unanticipated failure of system elements.

Remedial Action Scheme: A scheme designed to detect predetermined System conditions and automatically take corrective actions that may include, but are not limited to, adjusting or tripping generation (MW and Mvar), tripping load, or reconfiguring a System(s). RAS accomplish objectives such as:
• Meet requirements identified in the NERC Reliability Standards;
• Maintain Bulk Electric System (BES) stability;
• Maintain acceptable BES voltages;
• Maintain acceptable BES power flows;
• Limit the impact of Cascading or extreme events. The following do not individually constitute a RAS:
a. Protection Systems installed for the purpose of detecting Faults on BES Elements and isolating the faulted Elements
b. Schemes for automatic underfrequency load shedding (UFLS) and automatic undervoltage load shedding (UVLS) comprised of only distributed relays
c. Out-of-step tripping and power swing blocking
d. Automatic reclosing schemes
Schemes applied on an Element for non-Fault conditions, such as, but not limited to, generator loss-of- field, transformer top-oil temperature, overvoltage, or overload to protect the Element against damage by removing it from service

Remedial Action Scheme Continued: f. Controllers that switch or regulate one or more of the following: series or shunt reactive devices, flexible alternating current transmission system (FACTS) devices, phase-shifting transformers, variable- frequency transformers, or tap-changing transformers; and, that are located at and monitor
quantities solely at the same station as the Element being switched or regulated
g. FACTS controllers that remotely switch static shunt reactive devices located at other stations to regulate the output of a single FACTS device
h. Schemes or controllers that remotely switch shunt reactors and shunt capacitors for voltage regulation that would otherwise be manually switched
i. Schemes that automatically de-energize a line for a non-Fault operation when one end of the line is open
j. Schemes that provide anti-islanding protection (e.g., protect load from effects of being isolated with generation that may not be capable of maintaining acceptable frequency and voltage)
k. Automatic sequences that proceed when manually initiated solely by a System Operator
l. Modulation of HVdc or FACTS via supplementary controls, such as angle damping or frequency damping applied to damp local or inter-area oscillations
m. Sub-synchronous resonance (SSR) protection schemes that directly detect sub-synchronous quantities (e.g., currents or torsional oscillations)

Remedial Action Scheme Continued: n. Generator controls such as, but not limited to, automatic generation control (AGC), generation excitation [e.g. automatic voltage regulation (AVR) and power system stabilizers (PSS)], fast valving, and speed governing

Removable Media: Storage media that:
1. are not Cyber Assets,
2. are capable of transferring executable code,
3. can be used to store, copy, move, or access data, and
4. are directly connected for 30 consecutive calendar days or less to a:
• BES Cyber Asset,
• network within an Electronic Security Perimeter (ESP) containing high or medium impact BES Cyber Systems, or
• Protected Cyber Asset associated with high or medium impact BES Cyber Systems.
Examples of Removable Media include, but are not limited to, floppy disks, compact disks, USB flash drives, external hard drives, and other flash memory cards/drives that contain nonvolatile

Reportable Balancing Contingency Event: Any Balancing Contingency Event occurring within a one-minute interval of an initial sudden decline in ACE based on EMS scan rate data that results in a loss of MW output less than or equal to the Most Severe Single Contingency, and greater than or equal to the lesser amount of:
(i) 80% of the Most Severe Single Contingency, or (ii) the amount listed below for the applicable Interconnection. Prior to any given calendar quarter, the 80% threshold may be reduced by the responsible entity upon written notification to the Regional Entity.
• Eastern Interconnection – 900 MW
• Western Interconnection – 500 MW
• ERCOT – 800 MW
• Quebec – 500 MW

Reportable Cyber Security Incident: A Cyber Security Incident that compromised or disrupted:
– A BES Cyber System that performs one or more reliability tasks of a functional entity;
– An Electronic Security Perimeter of a high or medium impact BES Cyber System; or
An Electronic Access Control or Monitoring System of a high or medium impact BES Cyber System.

Reportable Disturbance: Any event that causes an ACE change greater than or equal to 80% of a Balancing Authority’s or reserve sharing group’s most severe contingency. The definition of a reportable disturbance is specified by each Regional Reliability Organization. This definition may not be retroactively adjusted in response to observed performance.

Reporting ACE: The scan rate values of a Balancing Authority Area’s (BAA) Area Control Error (ACE) measured in MW includes the difference between the Balancing Authority Area’s Actual Net Interchange and its Scheduled Net Interchange, plus its Frequency Bias Setting obligation, plus correction for any known meter error. In the Western Interconnection, Reporting ACE includes Automatic Time Error Correction (ATEC).
Reporting ACE is calculated as follows:
Reporting ACE = (NI_A − NI_S) − 10B (F_A − FS) – I_ME
Reporting ACE is calculated in the Western Interconnection as follows: Reporting ACE = (NI_A − NI_S) − 10B (F_A − F_S) – I_ME + I_ATEC
Where:
• NI_A = Actual Net Interchange.
• NI_S = Scheduled Net Interchange.
• B = Frequency Bias Setting.
• F_A = Actual Frequency.
• F_S = Scheduled Frequency.
• I_ME = Interchange Meter Error.
• I_ATEC = Automatic Time Error Correction.

Reporting ACE (continued): All NERC Interconnections operate using the principles of Tie-line Bias (TLB) Control and require the use of an ACE equation similar to the Reporting ACE defined above. Any modification(s) to this specified Reporting ACE equation that is(are) implemented for all BAAs on an Interconnection and is(are) consistent with the following four principles of Tie Line Bias control will provide a valid alternative to this Reporting ACE equation:
1. All portions of the Interconnection are included in exactly one BAA so that the sum of all BAAs’ generation, load, and loss is the same as total Interconnection generation, load, and loss;
2. The algebraic sum of all BAAs’ Scheduled Net Interchange is equal to zero at all times and the sum of all BAAs’ Actual Net Interchange values is equal to zero at all times;
3. The use of a common Scheduled Frequency F_S for all BAAs at all times; and,
Excludes metering or computational errors. (The inclusion and use of the I_ME term corrects for known metering or computational errors.)

Request for Interchange: A collection of data as defined in the NAESB Business Practice Standards submitted for the purpose of implementing bilateral Interchange between Balancing Authorities or an energy transfer within a single Balancing Authority.

Reserve Sharing Group: A group whose members consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating reserves required for each Balancing Authority’s use in recovering from contingencies within the group. Scheduling energy from an Adjacent Balancing Authority to aid recovery need not constitute reserve sharing provided the transaction is ramped in over a period the supplying party could reasonably be expected to load generation in (e.g., ten minutes). If the transaction is ramped in quicker (e.g., between zero and ten minutes) then, for the purposes of disturbance control performance, the areas become a Reserve Sharing

Resource Planner: The entity that develops a long-term (generally one year and beyond) plan for the resource adequacy of specific loads (customer demand and energy requirements) within a Planning Authority area.

Response Rate: The Ramp Rate that a generating unit can achieve under normal operating conditions expressed in megawatts per minute (MW/Min).

Right-of-Way: The corridor of land under a transmission line(s) needed to operate the line(s). The width of the corridor is established by engineering or construction standards as documented in either construction documents, pre-2007 vegetation maintenance records, or by the blowout standard in effect when the line was built. The ROW width in no case exceeds the applicable Transmission Owner’s or applicable Generator Owner’s legal rights but may be less based on the aforementioned criteria.

SERC Reliability Corporation (SERC): The SERC Reliability Corporation (SERC) is responsible for ensuring a reliable and secure electric grid across 16 southeastern and central states. The SERC region lies within the Eastern Interconnection, and includes the states of Alabama, Georgia, Mississippi, Missouri, North Carolina, South Carolina, Tennessee, and portions of Arkansas, Illinois, Kentucky, Louisiana, Oklahoma, Texas, Virginia, and Florida.

Scenario: Possible event.

Schedule: (Verb) To set up a plan or arrangement for an Interchange Transaction. (Noun) An Interchange Schedule.

Scheduled Frequency: 60.0 Hertz, except during a time correction.

Scheduled Net Interchange (NIS): The algebraic sum of all scheduled megawatt transfers, including Dynamic Schedules, to and from all Adjacent Balancing Authority areas within the same Interconnection, including the effect of scheduled ramps. Scheduled megawatt transfers on asynchronous DC tie lines directly connected to another Interconnection are excluded from Scheduled Net Interchange.

Scheduling Entity: An entity responsible for approving and implementing Interchange Schedules.

Scheduling Path: The Transmission Service arrangements reserved by the Purchasing-Selling Entity for a Transaction.

Sending Balancing Authority: The Balancing Authority exporting the Interchange.

Sink Balancing Authority: The Balancing Authority in which the load (sink) is located for an Interchange Transaction and any resulting Interchange Schedule.

Source Balancing Authority: The Balancing Authority in which the generation (source) is located for an Interchange Transaction and for any resulting Interchange Schedule.

Southwest Power Pool (SPP): SPP is a regional transmission organization (RTO): a nonprofit corporation mandated by the Federal Energy Regulatory Commission to ensure reliable supplies of power, adequate transmission infrastructure and competitive wholesale electricity prices on behalf of its members.

Special Protection System (Remedial Action Scheme): See “Remedial Action Scheme”

Spinning Reserve: Unloaded generation that is synchronized and ready to serve additional demand.

Stability: The ability of an electric system to maintain a state of equilibrium during normal and abnormal conditions or disturbances.

Stability Limit: The maximum power flow possible through some particular point in the system while maintaining stability in the entire system or the part of the system to which the stability limit refers.

Supervisory Control and Data Acquisition: A system of remote control and telemetry used to monitor and control the transmission system.

Supplemental Regulation Service: A method of providing regulation service in which the Balancing Authority providing the regulation service receives a signal representing all or a portion of the other Balancing Authority’s ACE.

Surge: A transient variation of current, voltage, or power flow in an electric circuit or across an electric system.

Sustained Outage: The deenergized condition of a transmission line resulting from a fault or disturbance following an unsuccessful automatic reclosing sequence and/or unsuccessful manual reclosing procedure.

System: A combination of generation, transmission, and distribution components.

System Operator: An individual at a Control Center of a Balancing Authority, Transmission Operator, or Reliability Coordinator, who operates or directs the operation of the Bulk Electric System (BES) in Real-time.

TLR (Transmission Loading Relief) Log (NERC added the spelled out term for TLR Log for clarification purposes.): Report required to be filed after every TLR Level 2 or higher in a specified format. The NERC IDC prepares the report for review by the issuing Reliability Coordinator. After approval by the issuing Reliability Coordinator, the report is electronically filed in a public area of the NERC Web site.

Telemetering: The process by which measurable electrical quantities from substations and generating stations are instantaneously transmitted to the control center, and by which operating commands from the control center are transmitted to the substations and generating stations.

Texas Reliability Entity (Texas RE): Texas Reliability Entity, Inc. (Texas RE) is a Texas 501(c)(3) non-profit corporation that is the Regional Entity for the area of Texas served by the Electric Reliability Council of Texas (ERCOT).

Thermal Rating: The maximum amount of electrical current that a transmission line or electrical facility can conduct over a specified time period before it sustains permanent damage by overheating or before it sags to the point that it violates public safety requirements.

Tie Line: A circuit connecting two Balancing Authority Areas.

Tie Line Bias: A mode of Automatic Generation Control that allows the Balancing Authority to 1.) maintain its Interchange Schedule and 2.) respond to Interconnection frequency error.

Time Error: The difference between the Interconnection time measured at the Balancing Authority(ies) and the time specified by the National Institute of Standards and Technology. Time error is caused by the accumulation of Frequency Error over a given period.

Time Error Correction: An offset to the Interconnection’s scheduled frequency to return the Interconnection’s Time Error to a predetermined value.

Total Flowgate Capability: The maximum flow capability on a Flowgate, is not to exceed its thermal rating, or in the case of a flowgate used to represent a specific operating constraint (such as a voltage or stability limit), is not to exceed the associated System Operating Limit.

Total Internal Demand: The Demand of a metered system, which includes the Firm Demand, plus any controllable and dispatchable DSM Load and the Load due to the energy losses incurred within the boundary of the metered system.

Total Transfer Capability: The amount of electric power that can be moved or transferred reliably from one area to another area of the interconnected transmission systems by way of all transmission lines (or paths) between those areas under specified system conditions.

Transaction: See Interchange Transaction.

Transfer Capability: The measure of the ability of interconnected electric systems to move or transfer power in a reliable manner from one area to another over all transmission lines (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). The transfer capability from “Area A” to “Area B” is not g enerally equal to the transfer capability from “Area B” to “Area A.”

Transfer Distribution Factor: See Distribution Factor.

Transient Cyber Asset: A Cyber Asset that is:
1. capable of transmitting or transferring executable code,
2. not included in a BES Cyber System,
3. not a Protected Cyber Asset (PCA) associated with high or medium impact BES Cyber Systems, and
4. directly connected (e.g., using Ethernet, serial, Universal Serial Bus, or wireless including near field or Bluetooth communication) for 30 consecutive calendar days or less to a:
• BES Cyber Asset,
• network within an Electronic Security Perimeter (ESP) containing high or medium impact BES Cyber Systems, or
• PCA associated with high or medium impact BES Cyber Systems.
Examples of Transient Cyber Assets include, but are not limited to, Cyber Assets used for data transfer, vulnerability assessment, maintenance, or troubleshooting purposes.

Transmission: An interconnected group of lines and associated equipment for the movement or transfer of electric energy between points of supply and points at which it is transformed for delivery to customers or is delivered to other electric systems.

Transmission Constraint: A limitation on one or more transmission elements that may be reached during normal or contingency system operations.

Transmission Customer: 1. Any eligible customer (or its designated agent) that can or does execute a Transmission
Service agreement or can or does receive Transmission Service.
2. Any of the following entities: Generator Owner, Load-Serving Entity, or Purchasing-Selling Entity.

Transmission Line: A system of structures, wires, insulators and associated hardware that carry electric energy from one point to another in an electric power system. Lines are operated at relatively high voltages varying from 69 kV up to 765 kV, and are capable of transmitting large quantities of electricity over long distances.

Transmission Operator: The entity responsible for the reliability of its “local” transmission system, and that operates or directs the operations of the transmission Facilities.

Transmission Operator Area: The collection of Transmission assets over which the Transmission Operator is responsible for operating.

Transmission Owner: The entity that owns and maintains transmission Facilities.

Transmission Planner: The entity that develops a long-term (generally one year and beyond) plan for the reliability (adequacy) of the interconnected bulk electric transmission systems within its portion of the Planning Authority area.

Transmission Reliability Margin: The amount of transmission transfer capability necessary to provide reasonable assurance that the interconnected transmission network will be secure. TRM accounts for the inherent uncertainty in system conditions and the need for operating flexibility to ensure reliable system operation as system conditions change.

Transmission Reliability Margin Implementation Document: A document that describes the implementation of a Transmission Reliability Margin methodology, and provides information related to a Transmission Operator’s calculation of TRM.

Transmission Service: Services provided to the Transmission Customer by the Transmission Service Provider to move energy from a Point of Receipt to a Point of Delivery.

Transmission Service Provider: The entity that administers the transmission tariff and provides Transmission Service to Transmission Customers under applicable Transmission Service agreements.

Undervoltage Load Shedding Program: An automatic load shedding program, consisting of distributed relays and controls, used to mitigate undervoltage conditions impacting the Bulk Electric System (BES), leading to voltage instability, voltage collapse, or Cascading. Centrally controlled undervoltage-based load shedding is not included.

Vegetation: All plant material, growing or not, living or dead.

Vegetation Inspection: The systematic examination of vegetation conditions on a Right-of-Way and those vegetation conditions under the applicable Transmission Owner’s or applicable Generator Owner’s control that are likely to pose a hazard to the line(s) prior to the next planned maintenance or inspection. This may be combined with a general line inspection.

Western Electricity Coordinating Council (WECC): WECC promotes bulk power system reliability and security in the Western Interconnection. WECC is the Regional Entity responsible for compliance monitoring and enforcement and oversees reliability planning and assessments.

Wide Area: The entire Reliability Coordinator Area as well as the critical flow and status information from adjacent Reliability Coordinator Areas as determined by detailed system studies to allow the calculation of Interconnected Reliability Operating Limits.

Year One: The first twelve month period that a Planning Coordinator or a Transmission Planner is responsible for assessing. For an assessment started in a given calendar year, Year One includes the forecasted peak Load period for one of the following two calendar years. For example, if a Planning Assessment was started in 2011, then Year One includes the forecasted peak Load period for either 2012 or 2013.

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