IEC TS 61968-2:2011

Application integration at electric utilities - System interfaces for distribution management - Part 2: Glossary

IEC/TS 61968-2:2011(E) identifies and explains terms and abbreviations used in the remaining parts of IEC 61968. This glossary, accompanying the IEC 61968 series, is the second part in the series that, taken as a whole, defines interfaces for the major elements of an interface architecture for distribution management systems (DMS). This second edition contains numerous new terms in support of IEC 61968-9, as well as revisions to terms found in the first edition.
This publication is of core relevance for Smart Grid.

General Information

• Status: Published
• Publication Date: 29-Mar-2011
• ICS: 33.200 - Telecontrol. Telemetering
• Technical Committee: TC 57 - Power systems management and associated information exchange
• Drafting Committee: WG 14 - TC 57/WG 14
• Current Stage: PPUB - Publication issued
• Start Date: 30-Mar-2011
• Completion Date: 15-Jun-2011

Relations

• Revises: IEC TS 61968-2:2003 - Application integration at electric utilities - System interfaces for distribution management - Part 2: Glossary
• Effective Date: 05-Sep-2023

Overview

IEC TS 61968-2:2011 is the glossary part of the IEC 61968 series, titled Application integration at electric utilities – System interfaces for distribution management – Part 2: Glossary. This technical specification defines and explains the terms and abbreviations used throughout the IEC 61968 series. As a companion to the interface definitions in the other parts, it ensures consistent vocabulary for distribution management systems (DMS) and related utility IT integration efforts. The second edition adds many new terms (notably to support IEC 61968-9) and updates earlier definitions, making it a core reference for Smart Grid interoperability and system integration.

Key Topics and Requirements

• Terminology for DMS and ICT: Clear definitions for distribution management, information and communication technology (ICT) concepts, and cross-domain terms used across the series.
• Abstract and application components: Definitions that underpin the IEC 61968 interface reference model (e.g., abstract component, application component, adapter).
• Metering and AMI vocabulary: Standardized terms for metering systems (advanced meters, automated meter reading, advanced metering infrastructure, advanced meter management).
• Measurement and power terms: Common electrical terms such as active power, apparent power, energy units, and accuracy-related vocabulary.
• Abbreviations list and bibliography: A consolidated glossary of abbreviations used in IEC 61968 and references to authoritative sources (e.g., Electropedia, IEC 60050).
• Cross-references and notes: Usage guidance, cross-references between related terms, and citations that support consistent interpretation across all IEC 61968 parts.

Applications

IEC TS 61968-2 is a practical reference to:

• Promote consistent terminology when designing and documenting system interfaces for DMS.
• Support inter-application integration efforts where heterogeneous legacy and new systems must exchange data via middleware and message brokering.
• Aid the development of interface specifications, mapping documents, API contracts, and message schemas used in Smart Grid and utility IT projects.
• Reduce ambiguity in procurement documents, technical requirements, and vendor communications by using standardized definitions.

Who Uses This Standard

• Utility IT architects and engineers designing DMS integrations
• System integrators and middleware vendors
• Metering and AMI solution providers
• Consultants, regulators, and standards committees working on Smart Grid interoperability
• Software developers and testing teams implementing IEC 61968-compliant interfaces

Related Standards

• Other parts of the IEC 61968 series (interface definitions and mappings)
• IEC 61968-9 (specific expansion supported by the 2nd edition glossary)
• IEC Electropedia and IEC 60050 for broader electrotechnical vocabulary

By centralizing definitions, IEC TS 61968-2 improves clarity, supports interoperability, and accelerates Smart Grid and DMS integration projects through consistent, authoritative terminology.

Standards Content (Sample)

IEC TS 61968-2 ®
Edition 2.0 2011-03
TECHNICAL
SPECIFICATION
Application integration at electric utilities – System interfaces for distribution
management –
Part 2: Glossary
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IEC TS 61968-2 ®
Edition 2.0 2011-03
TECHNICAL
SPECIFICATION
Application integration at electric utilities – System interfaces for distribution
management –
Part 2: Glossary
INTERNATIONAL
ELECTROTECHNICAL
COMMISSION
ICS 33.200 ISBN 978-2-8891-2425-1

– 2 – TS 61968-2 © IEC:2011(E)
CONTENTS
FOREWORD . 3
INTRODUCTION . 5
1 Scope . 6
2 Terms and definitions . 6
3 Glossary of abbreviations in the IEC 61968 series . 48
Bibliography . 51

TS 61968-2 © IEC:2011(E) – 3 –
INTERNATIONAL ELECTROTECHNICAL COMMISSION
____________
APPLICATION INTEGRATION AT ELECTRIC UTILITIES –
SYSTEM INTERFACES FOR DISTRIBUTION MANAGEMENT –

Part 2: Glossary
FOREWORD
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The main task of IEC technical committees is to prepare International Standards. In
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specification when
• the required support cannot be obtained for the publication of an International Standard,
despite repeated efforts, or
• the subject is still under technical development or where, for any other reason, there is the
future but no immediate possibility of an agreement on an International Standard.
Technical specifications are subject to review within three years of publication to decide
whether they can be transformed into International Standards.
IEC 61968-2, which is a technical specification, has been prepared by IEC technical
committee 57: Power systems management and associated information exchange.

– 4 – TS 61968-2 © IEC:2011(E)
The text of this technical specification is based on the following documents:
TS Report on voting
57/1054/DTS 57/1088/RVC
Full information on the voting for the approval of this technical specification can be found in
the report on voting indicated in the above table.
This publication has been drafted in accordance with the ISO/IEC Directives Part 2.
This second edition cancels and replaces the first edition published in 2003. This second
edition constitutes a technical revision. It contains numerous new terms in support of
IEC 61968-9, as well as revisions to terms found in the first edition.
The reader will find citations to bibliographic references within square brackets [ ] below many
of the term definitions. Cross references between many related terms have also been added
to this edition. These are located among the notes and begin with the words “See also.”
A list of all the parts in the IEC 61968 series, published under the general title Application
integration at electric utilities – System interfaces for distribution management can be found
on the IEC website.
A bilingual version may be issued at a later date.
The committee has decided that the contents of this publication will remain unchanged until
the stability date indicated on the IEC web site under "http://webstore.iec.ch" in the data
related to the specific publication. At this date, the publication will be
• transformed into an International standard,
• reconfirmed,
• withdrawn,
• replaced by a revised edition, or
• amended.
TS 61968-2 © IEC:2011(E) – 5 –
INTRODUCTION
The IEC 61968 series is intended to facilitate inter-application integration, as opposed to
intra-application integration, of the various distributed software application systems supporting
the management of utility electrical distribution networks. Intra-application integration is aimed
at programs in the same application system, usually communicating with each other using
middleware that is embedded in their underlying runtime environment, and tends to be
optimized for close, real-time, synchronous connections and interactive request/reply or
conversation communication models. IEC 61968, by contrast, is intended to support the inter-
application integration of a utility enterprise that needs to connect disparate applications that
are already built or new (legacy or purchased applications), each supported by dissimilar
runtime environments. Therefore, IEC 61968 is relevant to loosely coupled applications with
more heterogeneity in languages, operating systems, protocols and management tools.
IEC 61968 is intended to support applications that need to exchange data on an event driven
basis. IEC 61968 is intended to be implemented with middleware services that broker
messages among applications, and will complement, but not replace utility data warehouses,
database gateways, and operational stores.
The series of standards will be using a lot of definitions, terms and abbreviations from the
area of distribution management as well as from the area of Information and Communication
Technology. This glossary part defines the terms and abbreviations as they are used in the
context of this series of standards.

– 6 – TS 61968-2 © IEC:2011(E)
APPLICATION INTEGRATION AT ELECTRIC UTILITIES –
SYSTEM INTERFACES FOR DISTRIBUTION MANAGEMENT –

Part 2: Glossary
1 Scope
This part of IEC 61968 identifies and explains terms and abbreviations used in the remaining
parts of IEC 61968.
This glossary, accompanying the IEC 61968 series, is the second part in the series that, taken
as a whole, defines interfaces for the major elements of an interface architecture for
distribution management systems (DMS).
As used in IEC 61968, a DMS consists of various distributed application components for the
utility to manage electrical distribution networks. These capabilities include monitoring and
control of equipment for power delivery, management processes to ensure system reliability,
voltage management, demand-side management, outage management, work management,
automated mapping and facilities management.
2 Terms and definitions
For the purposes of the IEC 61968 series, the following terms and definitions apply.
2.1
abstract component
smallest logical block of software considered in the IEC 61968 interface reference model
NOTE Abstract components have interfaces that will be defined in parts 3 to 10 of the IEC 61968 series. It is
expected that different vendors will supply physical application components that support the interfaces for one or
more abstract components.
2.2
absolute data
data which is based on a fixed sample at a prescribed moment in time
NOTE 1 The data may have been scaled and may consist of a signed value (as opposed to unsigned).
[Aclara 2008]
NOTE 2 See also: "incremental data".
2.3
account number
unique number issued by a customer information system to identify a specific customer
account within a given utility
[Aclara 2008]
2.4
accuracy (of a measurement)
quality of freedom from mistake or error, that is, of conformity to truth or to a rule
NOTE 1 Accuracy is distinguished from precision as in the following example: A six-place table is more precise
than a four-place table. However, if there are errors in the six-place table, it may be more or less accurate than the
four-place table.
TS 61968-2 © IEC:2011(E) – 7 –
NOTE 2 The accuracy of an indicated or recorded value is expressed by the ratio of the error of the indicated
value to the true value. It is usually expressed in percent. Since the true value cannot be determined exactly, the
measured or calculated value of highest available accuracy is taken to be the true value or reference value.
Comparison of results obtained by different measurement procedures is often useful in establishing the true value.
[IEEE 2000]
NOTE 3 See also: "resolution”.
2.5
active energy
real energy
integral of active power with respect to time
NOTE In a distribution network, active energy is normally measured in kiloWatthours (kWh).
[Aclara 2008]
2.6
active power
real power
under periodic conditions, mean value, taken over one period T, of the instantaneous power
p:
T
P= pdt
∫
T
NOTE 1 Under sinusoidal conditions, the active power is the real part of the complex power.
NOTE 2 The SI unit for active power is the watt.
[IEC 60050-131:2002, 131-11-42]
NOTE 3 Active power in a distribution network is normally expressed in kW.
2.7
adapter
object adapter
layer of software that connects one component to another component
NOTE 1 An example of a component would be an application.
NOTE 2 An example of an adapter would be an interface implementation or a middleware implementation.
2.8
advanced meter
electric meter, new or appropriately retrofitted, which is 1) capable of measuring and
recording usage data in time differentiated registers, including hourly or such interval as is
specified by regulatory authorities, 2) allows electric consumers, suppliers and service
providers to participate in all types of price-based demand response programs, and 3) which
provides other data and functionality that address power quality and other electricity service
issues
[DRAM 2008]
2.9
advanced meter management
system capable of two-way communication with meters in a network for the purpose of
reading and controlling the meters
NOTE See also: “automated meter reading system” and “advanced metering infrastructure”.

– 8 – TS 61968-2 © IEC:2011(E)
2.10
alarm
message which indicates an abnormal condition, or that a measurement has exceeded a
preset value
[Aclara 2008]
2.11
apparent energy
integral of apparent power with respect to time
NOTE In a distribution network, apparent energy is ordinarily measured in kiloVoltAmpere hours (kVAh).
[Aclara 2008]
2.12
apparent power
product of the rms voltage U between the terminals of a two-terminal element or two-terminal
circuit and the rms electric current I in the element or circuit:
S = UI
NOTE 1 Under sinusoidal conditions, the apparent power is the modulus of the complex power.
NOTE 2 The SI unit for apparent power is the voltampere.
[IEC 60050-131:2002, 131-11-41]
NOTE 3 Apparent power in the distribution network is normally expressed in kVA.
NOTE 4 See also: "real power" and "reactive power".
2.13
application component
block of software with specific functions and interfaces
NOTE A distribution management system is considered to be a set of one or more applications. Each application
consists of one or more application components.
2.14
application programming interface
software specification and interface to a specific software application
NOTE This allows programmers to interface to a software application through a common interface.
[Itron 2008]
2.15
attribute
identifiable association between an object and a value
NOTE An attribute is a property of an object.
2.16
audit trail
information saved in a sequential form so that an event can be traced back to its origin
2.17
automated mapping/geofacilities
geospatial management system utilizing computer graphics technology to enter, store, and
update graphic and non-graphic information

TS 61968-2 © IEC:2011(E) – 9 –
NOTE Automated mapping reduces the cost and effort in map creation and maintenance and facility record
keeping. An automated mapping/ geospatial system processes geographic depictions and related non-graphic data
elements for each entity stored in a digital database. The graphic representations are referenced using a
coordinate system that relates to locations on the surface of the earth. Information in the database can be queried
and displayed based upon either the graphic or non-graphic attributes of the entities. The system provides the
utility a single, continuous electronic map of the service territory.
2.18
automated meter reading (system)
system where aggregated kWh usage, and in some cases demand, is retrieved via automated
means such as a drive-by vehicle, (fixed network,) or walk-by hand-held system
[DRAM 2008]
NOTE See also: “advanced meter management” and “advanced metering infrastructure”.
2.19
advanced metering infrastructure
communications hardware and software and associated system and data management
software that creates a network between advanced meters and utility business systems which
allows collection and distribution of information to customers and other parties such as
competitive retail suppliers, in addition to the utility itself
[DRAM 2008]
NOTE See also: “advanced meter management”.
2.20
automatic generation control
control of generation such that average hourly generation control follows a predispatch
schedule
NOTE Generation levels may be changed based on improving economic operation, emergency conditions, or
other improved conditions.
2.21
badge number
utility assigned number to the meter assembly
[Aclara 2008]
2.22
batch communication
communication where the function that owns the data sends information periodically in groups
NOTE In this mode there usually is a delay between the time that new information is available and when it is sent.
[MultiSpeak 2005]
2.23
big endian
ordering scheme for storing or transmitting data in which the most significant part of a
multiple-octet data is stored at the lowest octet address, and transmitted first
[IEC 61375-1:2007, 1.3.16]
NOTE See also: “little endian”.
2.24
billing demand
demand upon which billing to a customer is based, as specified in a rate schedule or contract
NOTE Billing demand may be based on the contract year, a contract minimum, or a previous maximum and
therefore does not necessarily coincide with the actual measured demand of the billing period.

– 10 – TS 61968-2 © IEC:2011(E)
[EEI 2005]
2.25
billing determinant
processed number, after all multiplications and adjustments are made (such as the
normalization of demand for a particular time scale), against which one multiplies the rate, to
determine the customer's bill
[Aclara 2008]
2.26
billing system
system to generate customer bills based upon metered data, and to provide information
regarding how the bill was created
NOTE A billing system is customarily a component of a customer information system.
2.27
billing window
regulatory timeframe in which meters must be read
NOTE The metering system, meter data management system, customer information system, and possibly other
systems must collaborate to read meters and deliver bills within the billing window.
[Aclara 2008]
2.28
breaker control
operator or manual opening or closing of a circuit breaker to isolate a fault or change the
network configuration
2.29
busbar
low impedance conductor to which several electric circuits can be separately connected
[IEC 60050-605:1983, 605-02-01]
2.30
busbar voltage control
regulation of voltage on the distribution substation busbar by means of transformer load tap
adjustments
NOTE Includes control of either single or paralleled substation transformers.
2.31
business functions
functions that form part of a business process
NOTE The functions may be performed manually and/or by one or more software applications.
2.32
cartographic map
map which displays planimetric and/or topographic information, and which may be used as a
base for a thematic layer
NOTE 1 Features, which may be included on a base map, are roads, rivers, major structures (buildings),
contours, etc. Feature presentation will, however, be map scale dependent.
NOTE 2 A cartographic feature is a term applied to the natural or cultural objects shown on a map or chart.
NOTE 3 See also: “geographic information system”.

TS 61968-2 © IEC:2011(E) – 11 –
2.33
channel
single flow path for digital data usually in distinction from other parallel paths
[Aclara 2008]
2.34
circuit
feeder
normal or actual configuration of a specific distribution circuit originating at a substation and
extending to either normally open switches of other distribution circuits or simply terminating
at different end points
2.35
class
definition of the attribute and methods for a type of object
NOTE See also: “object”.
2.36
clearance
safety permit
special authority given a person or persons working on de-energized cables, wires or
equipment
2.37
client (information technology)
requester of either or both services or resources
NOTE The client is the code or process that invokes an operation on an object.
2.38
cold load pickup
  loading imposed on a distribution feeder after service restoration in which some
loss of load diversity has occurred
[Lawhead, et. al. 2006]
  a controlled process used to restore power to such areas
2.39
common facilities
sets of programs and documents used by applications through a common interface
2.40
communication services
operation or function that an object and/or object class performs at the behest of another
object and/or class to integrate or adapt one or more components
NOTE To connect multiple components, an integration system must reconcile network and protocol differences.
2.41
component
set of services with a well-defined interface
NOTE A component can be as large as a complete (legacy) application which implements multiple services or as
small as a tiny widget which implements only one service. Components are independent software entities, which
encapsulate (private) data the component needs to know to perform its business function. For example, it can
perform any function that is required for distribution management. Typical categories of functions are showed in the
interface reference model.
– 12 – TS 61968-2 © IEC:2011(E)
2.42
component adapter
piece of software that has the role of making non-compliant components compliant with the
IEC 61968 series
NOTE 1 The component adapter only goes as far as necessary to make the component conformant to one or
more specific IEC interface specifications.
NOTE 2 A component adapter is a type of wrapper.
2.43
configuration data exchange
transfer of a particular group of settings to a device to allow it to operate correctly in the
network
NOTE 1 The transfer of information may be due to the commissioning of new equipment in the network, or to
enable one piece of equipment to take the place of another.
NOTE 2 In SCADA applications, inter-substation computer communications may occur to transfer
control/monitoring of devices to an adjacent substation due to reconfiguration or outage.
2.44
connectivity model
complete description of the electrical connections between lines, cables, switches, isolators
and other network components
2.45
consumer
customer
one who consumes the service provided by the utility
NOTE The consumer may be classified as a residential, commercial, industrial, or some other type of customer;
and may consume electricity, gas, water, and/or some other service.
[Aclara 2008]
2.46
consumption
metered usage of a given commodity over a specific period of time
NOTE Consumption is usually expressed in terms of a given flow direction and unit of measure.
2.47
contingency analysis
study of the effect of unexpected failure or outage of a system component
NOTE In distribution systems, it generally involves the study of how to restore power to customers when the
normal supply path is unavailable.
It is also an operating application which computes the potential effect of contingencies involving the loss of
generation and transmission facilities. A specific set of predefined contingencies is analyzed on a cyclic basis. It
simulates a contingency and calculates the changes in busbar voltages and power flows resulting from the
contingency. The base conditions for this calculation are the busbar voltages or power flows obtained from the load
flow program.
2.48
continuous cumulative maximum demand
continuous cumulative demand
the sum of the previous billing period maximum demands and the present period maximum
demand
[EEI 2002]
NOTE See also: “cumulative maximum demand”.

TS 61968-2 © IEC:2011(E) – 13 –
2.49
crew dispatch schedule
dynamically created schedule in which the work order for a specific crew is described
NOTE The schedule is based on the planned work or unplanned service interruptions in the infrastructure known
at the moment the schedule was created.
2.50
crew management
tracking of crew details schedules, crewmembers and all general activities related to outage
and general operational investigations
2.51
crew scheduling
dispatch of service people for customer service calls and distribution construction, and the
recording and monitoring of time spent on each call
2.52
crew tracking reports
dynamic information about the location, and progress of field crews in dealing with the work
assigned to the current control
2.53
critical peak pricing
type of dynamic pricing whereby the majority of kWh usage is priced on a TOU basis, but
where certain hours on certain days where the system is experiencing high peak demand are
subject to higher hourly energy prices that reflect market conditions for peak generation and
delivery during peak demand periods
NOTE These critical period prices may be known to electricity customers under conditions such as "day-ahead" or
"hour ahead" and are typically employed a limited number of times per year.
[DRAM 2008]
2.54
cumulative maximum demand
cumulative demand
the sum of the previous billing period maximum demand readings
NOTE 1 At the time of billing period reset, the maximum demand for the most recent billing period is added to the
previously accumulated total of all maximum demands.
[EEI 2002]
NOTE 2 See also: “maximum demand”, and “continuous cumulative maximum demand”.
2.55
current control
management of circulating current in a parallel transformer configuration at the distribution
substation
NOTE Current control reduces substation transformer load losses and minimizes transformer overloads by
balancing loading between transformers in the same or adjacent distribution substations.
2.56
current transformer
instrument transformer designed for use in the measurement or control of current
NOTE The current transformer’s primary winding, which may be a single turn or bus bar, is connected in series
with the load. It is normally used to reduce primary current by a known ratio to within the range of a connected
measuring device.
[EEI 2002]
– 14 – TS 61968-2 © IEC:2011(E)
2.57
current transformer ratio
effective turns ratio of a current transformer
[Aclara 2008]
2.58
customer information system
system that maintains customer information
NOTE The customer information system may consist of a suite of applications, typically provided and integrated
by a single vendor, which in addition to maintaining customer information, perform customer billing, finance,
accounting functions, and possibly other services.
[MultiSpeak 2005, modified]
2.59
customer outage analysis
up-to-date information on the number of customers affected by a specific network incident
2.60
customer program
classification scheme for the sale of energy to consumers according to a particular tariff
NOTE 1 The program may specify the purpose, conditions on the time of use, the service voltage(s), the volumes
consumed, and/or other terms as a condition of the sale.
NOTE 2 Utilities may promote particular programs to their industrial, commercial, agricultural, and residential
customers in an effort to encourage a particular behaviour, or to make them aware of their options.
2.61
cycle day
recurring day on the calendar, within each month, upon which a meter reading is to occur
[Aclara 2008]
2.62
data element
generic term for a data item to be read from or written to a meter or other end device
NOTE A data element may be a “measurement” or a “parameter.”
[Aclara 2008, modified]
2.63
data logger
system to measure a number of variables and make written tabulations and/or record in a
form suitable for computer input
[IEEE 2000]
2.64
data model
collection of descriptions of data structures and their contained fields, together with the
operations or functions that manipulate them
2.65
data warehouse
repository of data
TS 61968-2 © IEC:2011(E) – 15 –
2.66
database management/security
process of maintaining the integrity of database
NOTE 1 Database security management provides the required maintenance of data elements and controls the
data requirements of other subsystems.
NOTE 2  Security management encompasses access control authorization facilities and partitioning the network.
Security management may also include support for encryption and maintenance of security logs
2.67
deferred synchronous request
request where the client does not wait for completion of the request, but does intend to accept
results later
NOTE This is in contrast to synchronous request and one-way request.
2.68
demand
average power or a related quantity over a specified interval of time
NOTE 1 Demand (in a distribution network) is expressed in kW, kVA, kVAr, or other suitable units.
NOTE 2 An interval may be 1 min, 5 min, 10 min, 15 min, 30 min, or 60 min.
NOTE 3 “Forward energy” is generally used as the basis for a demand calculation since the primary purpose is to
determine the capacity of the infrastructure required to serve the load.
NOTE 4 While meters commonly store demand data measured to the tariff-prescribed demand-interval, scaling
must commonly occur before these values can be truly expressed in SI units such as kW or kVAr. It is important for
data producers and data consumers to be clear regarding which scalars have been applied and which are pending.
[ANSI 2001, modified, IEEE 2000, modified, and EEI 2002, modified]
NOTE 5 See also: "load".
2.69
demand reset
the process of zeroing the maximum demand accumulator
NOTE This usually involves shifting the “present maximum demand” to become the new “previous maximum
demand,” and zeroing the “present maximum demand.”
[Aclara 2008]
2.70
demand reset count
count which represents the number of times a given meter has undergone a demand reset
[Aclara 2008]
2.71
demand response
reduction of customer energy usage at times of peak usage in order to help address system
reliability, reflect market conditions and pricing, and support infrastructure optimization or
deferral
NOTE 1 Demand response programs may include dynamic pricing/tariffs, price-responsive demand bidding,
contractually obligated and voluntary curtailment, and direct load control/cycling.
[DRAM 2008]
NOTE 2 See also: “direct load control”.

– 16 – TS 61968-2 © IEC:2011(E)
2.72
demand subinterval
portion of a demand interval used in rolling block demand calculations
NOTE A demand subinterval will always divide into a demand interval evenly. For example, a 15-minute demand
interval can divide into three 5-minute subintervals. A subinterval may be 1 min, 3 min, 5 min, 10 min, 15 min, or
30 min in length, provided that it divides into the corresponding demand interval one or more (integer) times.
[Aclara 2008]
2.73
demand-side management
functions that enable the utility to manage the demand curve in an emergency or planned
mode and to determine the customer load curve
NOTE Demand-side management functions include load control and load survey.
2.74
department
business function, for example handling outages, repairs on meters and repairs on the
distribution network, or customer care
2.75
derived
 data value calculated from one or more related measurements
NOTE 1 The calculation of the data value may be based on inputs which are of a different reading type than the
resultant reading type. For example, a value for “average power” might be computed (derived) from several
discrete “instantaneous power” measurements.
NOTE 2 See also: “estimated”.
 data value deduced from data at related locations
NOTE 3 When a number of meters below a given service transformer are de-energized, it might be possible to
infer that the service transformer and other service points below the same transformer all have an energization
status of de-energized and a quality of “derived (inferred).”
2.76
detent
mechanism which permits a meter dial to spin in one direction only (i.e. “forward” or “reverse”
only)
[Aclara 2008]
2.77
device operation history
data concerning the operation of electrical devices, often used in condition-based
maintenance schemes
2.78
diagnostic
process by which hardware malfunctions may be detected
[IEEE 2000]
2.79
dial reading
literally, the value presented by the meter dials to a human meter reader before applying any
display scalar indicated on a human readable label
[Aclara 2008]
TS 61968-2 © IEC:2011(E) – 17 –
2.80
direct load control
system or program that allows utilities, other load serving entities, or demand response
service providers to control user load via (1) directly cycling discretionary load of certain end
uses, (2) directly turning off such loads or (3) implementing custom load control strategies
that reduce peak usage
[DRAM 2008]
NOTE See also: “demand response” and “load control”.
2.81
dispatchable generation
generation under the control of a dispatcher or system operator
2.82
dispatchable load
load under the control of a load control system
NOTE Usually, such loads are selected in advance to be "deferrable" and to have negligible adverse impact on
the consumer. Examples include certain pumping, heating, and cooling applications.
2.83
dispatcher
person responsible for the controls at the master station
2.84
display multiplier
value the meter display must be multiplied by in order to obtain the metered usage
NOTE 1 The display multiplier is also known by its symbol “Kr”.
NOTE 2 The vast majority of meters have a value of Kr=1. Some meters have a value of Kr=10, or some other
value.
[Aclara 2008, modified]
2.85
distributed generation
small amounts of generation or pieces of generation equipment applied to a utility's
distribution system for the purpose of meeting local peak loads and/or displacing the need to
build additional (or upgrade) local distribution lines and infrastructure
NOTE Distributed generation may be in the form of gas or propane generators, fuel cells, etc.
[Itron 2008]
2.86
distributed load control
load controlled with utility commands from a remote location as well as from a local controller
that responds to local conditions
NOTE The customer may retain the option to override or modify the utility command.
2.87
distribution automation
actions to carry out automation of the distribution networks to enable automatic or remote
operation
NOTE 1 May include retrofitting switchgear with actuators/motors and the installation of RTU's.
NOTE 2 The action to restore supply post-fault may be initiated manually via a SCADA system, or automatically
by IED's, RTU's, FPI's or EFI's.

– 18 – TS 61968-2 © IEC:2011(E)
2.88
distribution management system
integration of business processes, hardware, software, and telecommunications equipment
that provide effective tools to manage the operational business processes related to network
management, outage management, power quality and other supporting operational practices
2.89
distribution network
distribution-voltage side of a substation including all of the lines, switches, transformers, and
protective devices
[Aclara 2008]
2.90
domain
scope
  business functions, software systems, physical equipment and
staff concerned with the distribution of electrical power to consumers
  software systems, equipment, staff and consumers of a single utility organization,
which could be a company or a department.
NOTE It is expected that within each utility domain, the systems, equipment, staff and consumers can be uniquely
identified. When information is exchanged between two utility domains, then identifiers may need extending with
the identity of the utility organization in order to guarantee global uniqueness.
2.91
dynamic pricing
retail prices for energy consumed that offer different prices during different time periods and
reflect the fact that power generation costs and wholesale power purchase costs vary during
different time periods
NOTE Types include time-of-use pricing, critical peak pricing and real-time pricing.
[DRAM 2008]
2.92
economic dispatch (function)
  adjustment of generation output among committed units in order to
minimize total operating cost
  scheduling of generation allocation among units in order to minimize total
operating cost
NOTE 1 The economic dispatch function is closely coupled with the automatic generation control function.
NOTE 2  The study mode will examine generation allocation over a longer period of time than the real-time mode.
(For example the study mode may examine a week-long schedule while real-time mode would examine only the
next hour.)
2.93
edited
value modified by a human
NOTE 1 In the context of VEE, “edited” means that the value has been modified by a human.
NOTE 2 See also: “derived”, and “estimated”.
2.94
electricity meter
device that measures and registers the integral of an electrical quantity with respect to time
[IEEE 2000]
TS 61968-2 © IEC:2011(E) – 19 –
2.95
electronic billing
  utility back-office application which uses computers and data communications,
as opposed to manual methods, to compute the customer’s bill and request payment
  a service provided by the utility in which there is a transmission of an electronic
customer usage bill on a periodic basis (typically monthly) to customers
2.96
emergency demand response programs
programs which are dispatched by system operators when system operating reserves drop to
levels such that load reductions are needed to maintain short-term system reliability
[DRAM 2008]
2.97
emergency response
off-site facility that has direct dial lines into regulatory agencies and the press for use in a
nuclear emergency
2.98
end device
equipment located at the end of a communication network
NOTE This equipment is usually on the customer premises. It may perform functions such as metrology, remote
connect/disconnect, load control, demand response, or other functions, and may have power relay and/or
secondary communications capability.
2.99
energization (status)
state of equipment describing if it is powered (“energized,” or “live”) or not powered (“de-
energized,” or “dead”)
NOTE See also: “verify meter power”.
2.100
energy accounting
accounting of energy sales and purchases to and from other utilities
NOTE 1 The data collection function of energy accounting tracks the actual amount of power exchanged with
other utilities.
NOTE 2 The account reconciliation function of energy accounting reports inadvertent data by comparing data
from the interchange planning function (planned power exchange) with the data from the data collection function of
energy accounting (actual power exchanged).
NOTE 3 The energy accounting function also includes billing co-generators and other utilities for power sold.
2.101
energy management system
computer system comprising a software platform providing basic support services and a set of
applications providing the functionality needed for the effective operation of electrical
generation and transmission facilities so as to assure adequate security of energy supply at
minimum cost
[IEC 61970-2:2004, 3.24]
2.102
estimated
data value determined from one or more measurements of the same kind taken from the same
or a similar source
– 20 – TS 61968-2 © IEC:2011(E)
NOTE 1 Estimated values are generally supplied because the original value was considered bad or was missing.
For example, a missing “60-minute Incremental IntervalData Net Energy (kWh)” reading might be computed
(estimated) from a number of readings of the same kind, taken from the same meter a few hours prior and a few
hours after.
NOTE 2 In the context of VEE, “estimated” means that the value has been determined by an algorithm that may
involve interpolation, extrapolation, substitution, or other prescribed logic.
NOTE 3 See also: “derived”.
2.103
equipment characteristics
data concerning the nature and operational parameters of physical devices designed to
perform particular functions
NOTE Characteristics can be viewed as a relationship between two or more variable quantities which describes
the performance of a device under a given condition.
2.104
equipment operation statistics
data such as the duration of time, the number of times, or other parameters that indicate how
a physical device has performed its function over a period of time
2.105
false alarm
an indicated fault where no fault exists
[IEC 62243:2005, 3.1.8]
2.106
fault
unplanned power interruption
2.107
fault analysis
review of fault records, sequence of events records, and other documentation produced upon
a fault to determine the cause of the fault, its total impact, steps taken by the system to
recover from the fault, and the possible avoidance of a futur
...

IEC/TS 61968-2 ®
Edition 2.0 2011-03
TECHNICAL
SPECIFICATION
Application integration at electric utilities – System interfaces for distribution
management –
Part 2: Glossary
IEC/TS 61968-2:2011(E)
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IEC/TS 61968-2 ®
Edition 2.0 2011-03
TECHNICAL
SPECIFICATION
Application integration at electric utilities – System interfaces for distribution
management –
Part 2: Glossary
INTERNATIONAL
ELECTROTECHNICAL
COMMISSION
PRICE CODE
XA
ICS 33.200 ISBN 978-2-88912-425-1

– 2 – TS 61968-2 © IEC:2011(E)
CONTENTS
FOREWORD . 3
INTRODUCTION . 5
1 Scope . 6
2 Terms and definitions . 6
3 Glossary of abbreviations in the IEC 61968 series . 48
Bibliography . 51

TS 61968-2 © IEC:2011(E) – 3 –
INTERNATIONAL ELECTROTECHNICAL COMMISSION
____________
APPLICATION INTEGRATION AT ELECTRIC UTILITIES –
SYSTEM INTERFACES FOR DISTRIBUTION MANAGEMENT –

Part 2: Glossary
FOREWORD
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all national electrotechnical committees (IEC National Committees). The object of IEC is to promote
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The main task of IEC technical committees is to prepare International Standards. In
exceptional circumstances, a technical committee may propose the publication of a technical
specification when
• the required support cannot be obtained for the publication of an International Standard,
despite repeated efforts, or
• the subject is still under technical development or where, for any other reason, there is the
future but no immediate possibility of an agreement on an International Standard.
Technical specifications are subject to review within three years of publication to decide
whether they can be transformed into International Standards.
IEC 61968-2, which is a technical specification, has been prepared by IEC technical
committee 57: Power systems management and associated information exchange.

– 4 – TS 61968-2 © IEC:2011(E)
The text of this technical specification is based on the following documents:
TS Report on voting
57/1054/DTS 57/1088/RVC
Full information on the voting for the approval of this technical specification can be found in
the report on voting indicated in the above table.
This publication has been drafted in accordance with the ISO/IEC Directives Part 2.
This second edition cancels and replaces the first edition published in 2003. This second
edition constitutes a technical revision. It contains numerous new terms in support of
IEC 61968-9, as well as revisions to terms found in the first edition.
The reader will find citations to bibliographic references within square brackets [ ] below many
of the term definitions. Cross references between many related terms have also been added
to this edition. These are located among the notes and begin with the words “See also.”
A list of all the parts in the IEC 61968 series, published under the general title Application
integration at electric utilities – System interfaces for distribution management can be found
on the IEC website.
A bilingual version may be issued at a later date.
The committee has decided that the contents of this publication will remain unchanged until
the stability date indicated on the IEC web site under "http://webstore.iec.ch" in the data
related to the specific publication. At this date, the publication will be
• transformed into an International standard,
• reconfirmed,
• withdrawn,
• replaced by a revised edition, or
• amended.
TS 61968-2 © IEC:2011(E) – 5 –
INTRODUCTION
The IEC 61968 series is intended to facilitate inter-application integration, as opposed to
intra-application integration, of the various distributed software application systems supporting
the management of utility electrical distribution networks. Intra-application integration is aimed
at programs in the same application system, usually communicating with each other using
middleware that is embedded in their underlying runtime environment, and tends to be
optimized for close, real-time, synchronous connections and interactive request/reply or
conversation communication models. IEC 61968, by contrast, is intended to support the inter-
application integration of a utility enterprise that needs to connect disparate applications that
are already built or new (legacy or purchased applications), each supported by dissimilar
runtime environments. Therefore, IEC 61968 is relevant to loosely coupled applications with
more heterogeneity in languages, operating systems, protocols and management tools.
IEC 61968 is intended to support applications that need to exchange data on an event driven
basis. IEC 61968 is intended to be implemented with middleware services that broker
messages among applications, and will complement, but not replace utility data warehouses,
database gateways, and operational stores.
The series of standards will be using a lot of definitions, terms and abbreviations from the
area of distribution management as well as from the area of Information and Communication
Technology. This glossary part defines the terms and abbreviations as they are used in the
context of this series of standards.

– 6 – TS 61968-2 © IEC:2011(E)
APPLICATION INTEGRATION AT ELECTRIC UTILITIES –
SYSTEM INTERFACES FOR DISTRIBUTION MANAGEMENT –

Part 2: Glossary
1 Scope
This part of IEC 61968 identifies and explains terms and abbreviations used in the remaining
parts of IEC 61968.
This glossary, accompanying the IEC 61968 series, is the second part in the series that, taken
as a whole, defines interfaces for the major elements of an interface architecture for
distribution management systems (DMS).
As used in IEC 61968, a DMS consists of various distributed application components for the
utility to manage electrical distribution networks. These capabilities include monitoring and
control of equipment for power delivery, management processes to ensure system reliability,
voltage management, demand-side management, outage management, work management,
automated mapping and facilities management.
2 Terms and definitions
For the purposes of the IEC 61968 series, the following terms and definitions apply.
2.1
abstract component
smallest logical block of software considered in the IEC 61968 interface reference model
NOTE Abstract components have interfaces that will be defined in parts 3 to 10 of the IEC 61968 series. It is
expected that different vendors will supply physical application components that support the interfaces for one or
more abstract components.
2.2
absolute data
data which is based on a fixed sample at a prescribed moment in time
NOTE 1 The data may have been scaled and may consist of a signed value (as opposed to unsigned).
[Aclara 2008]
NOTE 2 See also: "incremental data".
2.3
account number
unique number issued by a customer information system to identify a specific customer
account within a given utility
[Aclara 2008]
2.4
accuracy (of a measurement)
quality of freedom from mistake or error, that is, of conformity to truth or to a rule
NOTE 1 Accuracy is distinguished from precision as in the following example: A six-place table is more precise
than a four-place table. However, if there are errors in the six-place table, it may be more or less accurate than the
four-place table.
TS 61968-2 © IEC:2011(E) – 7 –
NOTE 2 The accuracy of an indicated or recorded value is expressed by the ratio of the error of the indicated
value to the true value. It is usually expressed in percent. Since the true value cannot be determined exactly, the
measured or calculated value of highest available accuracy is taken to be the true value or reference value.
Comparison of results obtained by different measurement procedures is often useful in establishing the true value.
[IEEE 2000]
NOTE 3 See also: "resolution”.
2.5
active energy
real energy
integral of active power with respect to time
NOTE In a distribution network, active energy is normally measured in kiloWatthours (kWh).
[Aclara 2008]
2.6
active power
real power
under periodic conditions, mean value, taken over one period T, of the instantaneous power
p:
T
P= pdt
∫
T
NOTE 1 Under sinusoidal conditions, the active power is the real part of the complex power.
NOTE 2 The SI unit for active power is the watt.
[IEC 60050-131:2002, 131-11-42]
NOTE 3 Active power in a distribution network is normally expressed in kW.
2.7
adapter
object adapter
layer of software that connects one component to another component
NOTE 1 An example of a component would be an application.
NOTE 2 An example of an adapter would be an interface implementation or a middleware implementation.
2.8
advanced meter
electric meter, new or appropriately retrofitted, which is 1) capable of measuring and
recording usage data in time differentiated registers, including hourly or such interval as is
specified by regulatory authorities, 2) allows electric consumers, suppliers and service
providers to participate in all types of price-based demand response programs, and 3) which
provides other data and functionality that address power quality and other electricity service
issues
[DRAM 2008]
2.9
advanced meter management
system capable of two-way communication with meters in a network for the purpose of
reading and controlling the meters
NOTE See also: “automated meter reading system” and “advanced metering infrastructure”.

– 8 – TS 61968-2 © IEC:2011(E)
2.10
alarm
message which indicates an abnormal condition, or that a measurement has exceeded a
preset value
[Aclara 2008]
2.11
apparent energy
integral of apparent power with respect to time
NOTE In a distribution network, apparent energy is ordinarily measured in kiloVoltAmpere hours (kVAh).
[Aclara 2008]
2.12
apparent power
product of the rms voltage U between the terminals of a two-terminal element or two-terminal
circuit and the rms electric current I in the element or circuit:
S = UI
NOTE 1 Under sinusoidal conditions, the apparent power is the modulus of the complex power.
NOTE 2 The SI unit for apparent power is the voltampere.
[IEC 60050-131:2002, 131-11-41]
NOTE 3 Apparent power in the distribution network is normally expressed in kVA.
NOTE 4 See also: "real power" and "reactive power".
2.13
application component
block of software with specific functions and interfaces
NOTE A distribution management system is considered to be a set of one or more applications. Each application
consists of one or more application components.
2.14
application programming interface
software specification and interface to a specific software application
NOTE This allows programmers to interface to a software application through a common interface.
[Itron 2008]
2.15
attribute
identifiable association between an object and a value
NOTE An attribute is a property of an object.
2.16
audit trail
information saved in a sequential form so that an event can be traced back to its origin
2.17
automated mapping/geofacilities
geospatial management system utilizing computer graphics technology to enter, store, and
update graphic and non-graphic information

TS 61968-2 © IEC:2011(E) – 9 –
NOTE Automated mapping reduces the cost and effort in map creation and maintenance and facility record
keeping. An automated mapping/ geospatial system processes geographic depictions and related non-graphic data
elements for each entity stored in a digital database. The graphic representations are referenced using a
coordinate system that relates to locations on the surface of the earth. Information in the database can be queried
and displayed based upon either the graphic or non-graphic attributes of the entities. The system provides the
utility a single, continuous electronic map of the service territory.
2.18
automated meter reading (system)
system where aggregated kWh usage, and in some cases demand, is retrieved via automated
means such as a drive-by vehicle, (fixed network,) or walk-by hand-held system
[DRAM 2008]
NOTE See also: “advanced meter management” and “advanced metering infrastructure”.
2.19
advanced metering infrastructure
communications hardware and software and associated system and data management
software that creates a network between advanced meters and utility business systems which
allows collection and distribution of information to customers and other parties such as
competitive retail suppliers, in addition to the utility itself
[DRAM 2008]
NOTE See also: “advanced meter management”.
2.20
automatic generation control
control of generation such that average hourly generation control follows a predispatch
schedule
NOTE Generation levels may be changed based on improving economic operation, emergency conditions, or
other improved conditions.
2.21
badge number
utility assigned number to the meter assembly
[Aclara 2008]
2.22
batch communication
communication where the function that owns the data sends information periodically in groups
NOTE In this mode there usually is a delay between the time that new information is available and when it is sent.
[MultiSpeak 2005]
2.23
big endian
ordering scheme for storing or transmitting data in which the most significant part of a
multiple-octet data is stored at the lowest octet address, and transmitted first
[IEC 61375-1:2007, 1.3.16]
NOTE See also: “little endian”.
2.24
billing demand
demand upon which billing to a customer is based, as specified in a rate schedule or contract
NOTE Billing demand may be based on the contract year, a contract minimum, or a previous maximum and
therefore does not necessarily coincide with the actual measured demand of the billing period.

– 10 – TS 61968-2 © IEC:2011(E)
[EEI 2005]
2.25
billing determinant
processed number, after all multiplications and adjustments are made (such as the
normalization of demand for a particular time scale), against which one multiplies the rate, to
determine the customer's bill
[Aclara 2008]
2.26
billing system
system to generate customer bills based upon metered data, and to provide information
regarding how the bill was created
NOTE A billing system is customarily a component of a customer information system.
2.27
billing window
regulatory timeframe in which meters must be read
NOTE The metering system, meter data management system, customer information system, and possibly other
systems must collaborate to read meters and deliver bills within the billing window.
[Aclara 2008]
2.28
breaker control
operator or manual opening or closing of a circuit breaker to isolate a fault or change the
network configuration
2.29
busbar
low impedance conductor to which several electric circuits can be separately connected
[IEC 60050-605:1983, 605-02-01]
2.30
busbar voltage control
regulation of voltage on the distribution substation busbar by means of transformer load tap
adjustments
NOTE Includes control of either single or paralleled substation transformers.
2.31
business functions
functions that form part of a business process
NOTE The functions may be performed manually and/or by one or more software applications.
2.32
cartographic map
map which displays planimetric and/or topographic information, and which may be used as a
base for a thematic layer
NOTE 1 Features, which may be included on a base map, are roads, rivers, major structures (buildings),
contours, etc. Feature presentation will, however, be map scale dependent.
NOTE 2 A cartographic feature is a term applied to the natural or cultural objects shown on a map or chart.
NOTE 3 See also: “geographic information system”.

TS 61968-2 © IEC:2011(E) – 11 –
2.33
channel
single flow path for digital data usually in distinction from other parallel paths
[Aclara 2008]
2.34
circuit
feeder
normal or actual configuration of a specific distribution circuit originating at a substation and
extending to either normally open switches of other distribution circuits or simply terminating
at different end points
2.35
class
definition of the attribute and methods for a type of object
NOTE See also: “object”.
2.36
clearance
safety permit
special authority given a person or persons working on de-energized cables, wires or
equipment
2.37
client (information technology)
requester of either or both services or resources
NOTE The client is the code or process that invokes an operation on an object.
2.38
cold load pickup
  loading imposed on a distribution feeder after service restoration in which some
loss of load diversity has occurred
[Lawhead, et. al. 2006]
  a controlled process used to restore power to such areas
2.39
common facilities
sets of programs and documents used by applications through a common interface
2.40
communication services
operation or function that an object and/or object class performs at the behest of another
object and/or class to integrate or adapt one or more components
NOTE To connect multiple components, an integration system must reconcile network and protocol differences.
2.41
component
set of services with a well-defined interface
NOTE A component can be as large as a complete (legacy) application which implements multiple services or as
small as a tiny widget which implements only one service. Components are independent software entities, which
encapsulate (private) data the component needs to know to perform its business function. For example, it can
perform any function that is required for distribution management. Typical categories of functions are showed in the
interface reference model.
– 12 – TS 61968-2 © IEC:2011(E)
2.42
component adapter
piece of software that has the role of making non-compliant components compliant with the
IEC 61968 series
NOTE 1 The component adapter only goes as far as necessary to make the component conformant to one or
more specific IEC interface specifications.
NOTE 2 A component adapter is a type of wrapper.
2.43
configuration data exchange
transfer of a particular group of settings to a device to allow it to operate correctly in the
network
NOTE 1 The transfer of information may be due to the commissioning of new equipment in the network, or to
enable one piece of equipment to take the place of another.
NOTE 2 In SCADA applications, inter-substation computer communications may occur to transfer
control/monitoring of devices to an adjacent substation due to reconfiguration or outage.
2.44
connectivity model
complete description of the electrical connections between lines, cables, switches, isolators
and other network components
2.45
consumer
customer
one who consumes the service provided by the utility
NOTE The consumer may be classified as a residential, commercial, industrial, or some other type of customer;
and may consume electricity, gas, water, and/or some other service.
[Aclara 2008]
2.46
consumption
metered usage of a given commodity over a specific period of time
NOTE Consumption is usually expressed in terms of a given flow direction and unit of measure.
2.47
contingency analysis
study of the effect of unexpected failure or outage of a system component
NOTE In distribution systems, it generally involves the study of how to restore power to customers when the
normal supply path is unavailable.
It is also an operating application which computes the potential effect of contingencies involving the loss of
generation and transmission facilities. A specific set of predefined contingencies is analyzed on a cyclic basis. It
simulates a contingency and calculates the changes in busbar voltages and power flows resulting from the
contingency. The base conditions for this calculation are the busbar voltages or power flows obtained from the load
flow program.
2.48
continuous cumulative maximum demand
continuous cumulative demand
the sum of the previous billing period maximum demands and the present period maximum
demand
[EEI 2002]
NOTE See also: “cumulative maximum demand”.

TS 61968-2 © IEC:2011(E) – 13 –
2.49
crew dispatch schedule
dynamically created schedule in which the work order for a specific crew is described
NOTE The schedule is based on the planned work or unplanned service interruptions in the infrastructure known
at the moment the schedule was created.
2.50
crew management
tracking of crew details schedules, crewmembers and all general activities related to outage
and general operational investigations
2.51
crew scheduling
dispatch of service people for customer service calls and distribution construction, and the
recording and monitoring of time spent on each call
2.52
crew tracking reports
dynamic information about the location, and progress of field crews in dealing with the work
assigned to the current control
2.53
critical peak pricing
type of dynamic pricing whereby the majority of kWh usage is priced on a TOU basis, but
where certain hours on certain days where the system is experiencing high peak demand are
subject to higher hourly energy prices that reflect market conditions for peak generation and
delivery during peak demand periods
NOTE These critical period prices may be known to electricity customers under conditions such as "day-ahead" or
"hour ahead" and are typically employed a limited number of times per year.
[DRAM 2008]
2.54
cumulative maximum demand
cumulative demand
the sum of the previous billing period maximum demand readings
NOTE 1 At the time of billing period reset, the maximum demand for the most recent billing period is added to the
previously accumulated total of all maximum demands.
[EEI 2002]
NOTE 2 See also: “maximum demand”, and “continuous cumulative maximum demand”.
2.55
current control
management of circulating current in a parallel transformer configuration at the distribution
substation
NOTE Current control reduces substation transformer load losses and minimizes transformer overloads by
balancing loading between transformers in the same or adjacent distribution substations.
2.56
current transformer
instrument transformer designed for use in the measurement or control of current
NOTE The current transformer’s primary winding, which may be a single turn or bus bar, is connected in series
with the load. It is normally used to reduce primary current by a known ratio to within the range of a connected
measuring device.
[EEI 2002]
– 14 – TS 61968-2 © IEC:2011(E)
2.57
current transformer ratio
effective turns ratio of a current transformer
[Aclara 2008]
2.58
customer information system
system that maintains customer information
NOTE The customer information system may consist of a suite of applications, typically provided and integrated
by a single vendor, which in addition to maintaining customer information, perform customer billing, finance,
accounting functions, and possibly other services.
[MultiSpeak 2005, modified]
2.59
customer outage analysis
up-to-date information on the number of customers affected by a specific network incident
2.60
customer program
classification scheme for the sale of energy to consumers according to a particular tariff
NOTE 1 The program may specify the purpose, conditions on the time of use, the service voltage(s), the volumes
consumed, and/or other terms as a condition of the sale.
NOTE 2 Utilities may promote particular programs to their industrial, commercial, agricultural, and residential
customers in an effort to encourage a particular behaviour, or to make them aware of their options.
2.61
cycle day
recurring day on the calendar, within each month, upon which a meter reading is to occur
[Aclara 2008]
2.62
data element
generic term for a data item to be read from or written to a meter or other end device
NOTE A data element may be a “measurement” or a “parameter.”
[Aclara 2008, modified]
2.63
data logger
system to measure a number of variables and make written tabulations and/or record in a
form suitable for computer input
[IEEE 2000]
2.64
data model
collection of descriptions of data structures and their contained fields, together with the
operations or functions that manipulate them
2.65
data warehouse
repository of data
TS 61968-2 © IEC:2011(E) – 15 –
2.66
database management/security
process of maintaining the integrity of database
NOTE 1 Database security management provides the required maintenance of data elements and controls the
data requirements of other subsystems.
NOTE 2  Security management encompasses access control authorization facilities and partitioning the network.
Security management may also include support for encryption and maintenance of security logs
2.67
deferred synchronous request
request where the client does not wait for completion of the request, but does intend to accept
results later
NOTE This is in contrast to synchronous request and one-way request.
2.68
demand
average power or a related quantity over a specified interval of time
NOTE 1 Demand (in a distribution network) is expressed in kW, kVA, kVAr, or other suitable units.
NOTE 2 An interval may be 1 min, 5 min, 10 min, 15 min, 30 min, or 60 min.
NOTE 3 “Forward energy” is generally used as the basis for a demand calculation since the primary purpose is to
determine the capacity of the infrastructure required to serve the load.
NOTE 4 While meters commonly store demand data measured to the tariff-prescribed demand-interval, scaling
must commonly occur before these values can be truly expressed in SI units such as kW or kVAr. It is important for
data producers and data consumers to be clear regarding which scalars have been applied and which are pending.
[ANSI 2001, modified, IEEE 2000, modified, and EEI 2002, modified]
NOTE 5 See also: "load".
2.69
demand reset
the process of zeroing the maximum demand accumulator
NOTE This usually involves shifting the “present maximum demand” to become the new “previous maximum
demand,” and zeroing the “present maximum demand.”
[Aclara 2008]
2.70
demand reset count
count which represents the number of times a given meter has undergone a demand reset
[Aclara 2008]
2.71
demand response
reduction of customer energy usage at times of peak usage in order to help address system
reliability, reflect market conditions and pricing, and support infrastructure optimization or
deferral
NOTE 1 Demand response programs may include dynamic pricing/tariffs, price-responsive demand bidding,
contractually obligated and voluntary curtailment, and direct load control/cycling.
[DRAM 2008]
NOTE 2 See also: “direct load control”.

– 16 – TS 61968-2 © IEC:2011(E)
2.72
demand subinterval
portion of a demand interval used in rolling block demand calculations
NOTE A demand subinterval will always divide into a demand interval evenly. For example, a 15-minute demand
interval can divide into three 5-minute subintervals. A subinterval may be 1 min, 3 min, 5 min, 10 min, 15 min, or
30 min in length, provided that it divides into the corresponding demand interval one or more (integer) times.
[Aclara 2008]
2.73
demand-side management
functions that enable the utility to manage the demand curve in an emergency or planned
mode and to determine the customer load curve
NOTE Demand-side management functions include load control and load survey.
2.74
department
business function, for example handling outages, repairs on meters and repairs on the
distribution network, or customer care
2.75
derived
 data value calculated from one or more related measurements
NOTE 1 The calculation of the data value may be based on inputs which are of a different reading type than the
resultant reading type. For example, a value for “average power” might be computed (derived) from several
discrete “instantaneous power” measurements.
NOTE 2 See also: “estimated”.
 data value deduced from data at related locations
NOTE 3 When a number of meters below a given service transformer are de-energized, it might be possible to
infer that the service transformer and other service points below the same transformer all have an energization
status of de-energized and a quality of “derived (inferred).”
2.76
detent
mechanism which permits a meter dial to spin in one direction only (i.e. “forward” or “reverse”
only)
[Aclara 2008]
2.77
device operation history
data concerning the operation of electrical devices, often used in condition-based
maintenance schemes
2.78
diagnostic
process by which hardware malfunctions may be detected
[IEEE 2000]
2.79
dial reading
literally, the value presented by the meter dials to a human meter reader before applying any
display scalar indicated on a human readable label
[Aclara 2008]
TS 61968-2 © IEC:2011(E) – 17 –
2.80
direct load control
system or program that allows utilities, other load serving entities, or demand response
service providers to control user load via (1) directly cycling discretionary load of certain end
uses, (2) directly turning off such loads or (3) implementing custom load control strategies
that reduce peak usage
[DRAM 2008]
NOTE See also: “demand response” and “load control”.
2.81
dispatchable generation
generation under the control of a dispatcher or system operator
2.82
dispatchable load
load under the control of a load control system
NOTE Usually, such loads are selected in advance to be "deferrable" and to have negligible adverse impact on
the consumer. Examples include certain pumping, heating, and cooling applications.
2.83
dispatcher
person responsible for the controls at the master station
2.84
display multiplier
value the meter display must be multiplied by in order to obtain the metered usage
NOTE 1 The display multiplier is also known by its symbol “Kr”.
NOTE 2 The vast majority of meters have a value of Kr=1. Some meters have a value of Kr=10, or some other
value.
[Aclara 2008, modified]
2.85
distributed generation
small amounts of generation or pieces of generation equipment applied to a utility's
distribution system for the purpose of meeting local peak loads and/or displacing the need to
build additional (or upgrade) local distribution lines and infrastructure
NOTE Distributed generation may be in the form of gas or propane generators, fuel cells, etc.
[Itron 2008]
2.86
distributed load control
load controlled with utility commands from a remote location as well as from a local controller
that responds to local conditions
NOTE The customer may retain the option to override or modify the utility command.
2.87
distribution automation
actions to carry out automation of the distribution networks to enable automatic or remote
operation
NOTE 1 May include retrofitting switchgear with actuators/motors and the installation of RTU's.
NOTE 2 The action to restore supply post-fault may be initiated manually via a SCADA system, or automatically
by IED's, RTU's, FPI's or EFI's.

– 18 – TS 61968-2 © IEC:2011(E)
2.88
distribution management system
integration of business processes, hardware, software, and telecommunications equipment
that provide effective tools to manage the operational business processes related to network
management, outage management, power quality and other supporting operational practices
2.89
distribution network
distribution-voltage side of a substation including all of the lines, switches, transformers, and
protective devices
[Aclara 2008]
2.90
domain
scope
  business functions, software systems, physical equipment and
staff concerned with the distribution of electrical power to consumers
  software systems, equipment, staff and consumers of a single utility organization,
which could be a company or a department.
NOTE It is expected that within each utility domain, the systems, equipment, staff and consumers can be uniquely
identified. When information is exchanged between two utility domains, then identifiers may need extending with
the identity of the utility organization in order to guarantee global uniqueness.
2.91
dynamic pricing
retail prices for energy consumed that offer different prices during different time periods and
reflect the fact that power generation costs and wholesale power purchase costs vary during
different time periods
NOTE Types include time-of-use pricing, critical peak pricing and real-time pricing.
[DRAM 2008]
2.92
economic dispatch (function)
  adjustment of generation output among committed units in order to
minimize total operating cost
  scheduling of generation allocation among units in order to minimize total
operating cost
NOTE 1 The economic dispatch function is closely coupled with the automatic generation control function.
NOTE 2  The study mode will examine generation allocation over a longer period of time than the real-time mode.
(For example the study mode may examine a week-long schedule while real-time mode would examine only the
next hour.)
2.93
edited
value modified by a human
NOTE 1 In the context of VEE, “edited” means that the value has been modified by a human.
NOTE 2 See also: “derived”, and “estimated”.
2.94
electricity meter
device that measures and registers the integral of an electrical quantity with respect to time
[IEEE 2000]
TS 61968-2 © IEC:2011(E) – 19 –
2.95
electronic billing
  utility back-office application which uses computers and data communications,
as opposed to manual methods, to compute the customer’s bill and request payment
  a service provided by the utility in which there is a transmission of an electronic
customer usage bill on a periodic basis (typically monthly) to customers
2.96
emergency demand response programs
programs which are dispatched by system operators when system operating reserves drop to
levels such that load reductions are needed to maintain short-term system reliability
[DRAM 2008]
2.97
emergency response
off-site facility that has direct dial lines into regulatory agencies and the press for use in a
nuclear emergency
2.98
end device
equipment located at the end of a communication network
NOTE This equipment is usually on the customer premises. It may perform functions such as metrology, remote
connect/disconnect, load control, demand response, or other functions, and may have power relay and/or
secondary communications capability.
2.99
energization (status)
state of equipment describing if it is powered (“energized,” or “live”) or not powered (“de-
energized,” or “dead”)
NOTE See also: “verify meter power”.
2.100
energy accounting
accounting of energy sales and purchases to and from other utilities
NOTE 1 The data collection function of energy accounting tracks the actual amount of power exchanged with
other utilities.
NOTE 2 The account reconciliation function of energy accounting reports inadvertent data by comparing data
from the interchange planning function (planned power exchange) with the data from the data collection function of
energy accounting (actual power exchanged).
NOTE 3 The energy accounting function also includes billing co-generators and other utilities for power sold.
2.101
energy management system
computer system comprising a software platform providing basic support services and a set of
applications providing the functionality needed for the effective operation of electrical
generation and transmission facilities so as to assure adequate security of energy supply at
minimum cost
[IEC 61970-2:2004, 3.24]
2.102
estimated
data value determined from one or more measurements of the same kind taken from the same
or a similar source
– 20 – TS 61968-2 © IEC:2011(E)
NOTE 1 Estimated values are generally supplied because the original value was considered bad or was missing.
For example, a missing “60-minute Incremental IntervalData Net Energy (kWh)” reading might be computed
(estimated) from a number of readings of the same kind, taken from the same meter a few hours prior and a few
hours after.
NOTE 2 In the context of VEE, “estimated” means that the value has been determined by an algorithm that may
involve interpolation, extrapolation, substitution, or other prescribed logic.
NOTE 3 See also: “derived”.
2.103
equipment characteristics
data concerning the nature and operational parameters of physical devices designed to
perform particular functions
NOTE Characteristics can be viewed as a relationship between two or more variable quantities which describes
the performance of a device under a given condition.
2.104
equipment operation statistics
data such as the duration of time, the number of times, or other parameters that indicate how
a physical device has performed its function over a period of time
2.105
false alarm
an indicated fault where no fault exists
[IEC 62243:2005, 3.1.8]
2.106
fault
unplanned power interruption
2.107
fault analysis
review of fault records, sequence of events records, and other documentation produced upon
a fault to determine the cause of the fault, its total impact, steps taken by the system to
recover from the fault, and the possible avoidanc
...