Specification of Transmission Service Standards

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Annexe 1 to report of working group on specification and negotiation of network services

Specification of Transmission Service Standards

(The material in this report is not a stand alone report but is provided for inclusion in the NECA Specification and Negotiation Working Group convened as part of the NECA Network Pricing Review. Specifically TNSPs were asked to propose performance measures and summarise their performance obligations as they stand. There is a proposal that the ‘traditional measures’ be extended to include more market responsive measures. This proposal will be dealt with more fully in a separate section of the NECA Working Group report but is referred to where appropriate in this document.)

Role of Transmission Standards

These are required to:

  1. Enable transmission customers to understand what is meant by standard service

  2. Ensure that service provision in excess of customer needs is not occurring at the expense of customers through regulated charges

  3. Ensure that service standards are not declining over time due to commercial pressures

  4. Provide a basis for negotiating non-standard service to the extent that this is practical for a shared transmission network.

Transmission Standard Service Levels Are Intrinsically Difficult to Measure

A fundamental requirement of transmission service is to maintain the continuing integrity of the interconnected transmission network itself and ensure that the overall security of the synchronised power system is not undermined. For example, system faults must be removed quickly enough to ensure that power system stability is not jeopardised. Failures at this level can have major social and economic consequences that are best understood if one could imagine a region wide system shutdown that is not restored for up to eight hours.

The NEM Code recognises this central feature of transmission service obligation in Sections 5.2.2 (d) and 5.2.3 (b) (3). These provisions require quality and security of supply to Network Users (including end users) to prevail over matters agreed in connection agreements (Sections 5.2.2 (d) and 5.2.3 (b) (3)). The Code definition of Network User unambiguously includes all end use customers. Performance standards must measure the degree of compliance with this obligation.
In essence, reducing the risk of these kinds of catastrophic events drives much of the investment, design, operation and maintenance activities of transmission network service providers. The simplest measure of success is that such events never occur. This measure provide little assurance to network users and regulators that there is an acceptably low level of risk of such an event occurring. The measurement of such risk is intrinsically difficult and, as far as the author is aware, has not been satisfactorily addressed anywhere in the world.
The best that has occurred is to develop indicators of the underlying ‘health’ of the transmission network through a range of equipment outage statistics. These statistics are monitored over time to provide early warning of declines in ‘health’.
It has also been proposed that transmission network service providers have an obligation to act in a way that minimises the impact of transmission constraints on pool price. This is based on the idea that transmission constraints lead to sub-optimal generator dispatch causing wholesale energy prices to be higher than they should be.
While there is merit in this approach, as far as the author of this paper is aware there is no Code requirement that a transmission network has this service obligation. If it is agreed that this is a service obligation it ought to be codified with a requirement that transmission network service providers receive the information (including bid prices) to enable this measure to be managed.
Whether this aspect of transmission service is easy to measure in practice is yet to be established, although in theory it should be possible. In addition, there is reason to believe that it may be a volatile measure depending as much on the interregional supply-demand balance between generation and load as the performance of transmission networks.
In short, measuring transmission service levels is not without difficulty. The next section sets out the approaches currently undertaken by transmission businesses.

Current Measures of Transmission Service Performance

Current measures of transmission service provide valuable information on the health of the transmission network and provide reasonable assurance to Network Users that NEM Code requirements, as they presently stand, are being met.
It has been proposed that transmission service obligations ought to be extended to include responsiveness to wholesale energy market signals. In particular, it is argued that unnecessary constraints on generator market access results in increased energy prices to customers. Such constraints could be inter or intra regional. This section acknowledges this as an area for development, including the development of appropriate performance indicators, but confines discussion to the currently used performance indicators.
At the highest level Australian transmission owners have established two key performance measures as follows:


(Unsupplied energy - calculated from MWh’s unsupplied to transmission customers)
This is MWh unsupplied divided by MW peak demand (multiplied by 60 to convert to system minutes). It is a measure of the service level of the transmission network as perceived by customers of the network.
Energy not supplied to customers as a result of any of the following events should be included as unsupplied energy:

  • Unplanned Outage – forced (required to be taken out of service because of emergency (eg. safety))

  • Unplanned Outage - fault (automatically removed from service because of electrical fault)

It is important to realise that the unsupplied energy should not include energy not supplied because of generation shortfalls. This is market failure not transmission service failure.


This is the actual circuit hours available for all transmission network elements (100kV and above), divided by the total possible circuit hours available. It provides a measure of overall system availability as well as the proportion of planned, forced and fault outages.

(Circuit unavailability may be caused by any of the following:

  • Planned Outage – maintenance

  • Planned Outage – construction

  • Unplanned Outage – forced

  • Unplanned Outage – fault

This measure can be used in relation to:

  • Circuit availability (either overhead lines or underground cables)

  • Transformer availability

  • Circuit breaker availability

The system minutes attempts to normalise measures of the reliability of transmission systems for different system maximum demands and is used as a first order point of comparison between transmission entities. It focuses on the overriding NEM Code requirement to deliver reliable and secure transmission service to Network Users (see below) and encapsulates the combined effectiveness of network planning, design, operation and maintenance. It is of limited statistical value in that it only infers any changes in risk of a major transmission system failure (ie. changes in network security).

Plant availability is of value in monitoring the ‘health’ of an existing transmission network. It can be applied at an aggregate level or to individual plant groups. It can also be broken down to reflect availability impacts due to planned outages and availability impacts due to unplanned outages. In both cases the availability can be improved by improving restoration times.
Each transmission entity uses focussed variants of the plant availability measure to monitor the performance of various plant categories and separate out the number of outages from the average duration.
To extract most value from these kinds of indicators in terms of monitoring transmission system health it is most appropriate to adopt a time series approach (over say 5 year regulatory reset periods) rather than absolute standards to be achieved by all transmission businesses. This is because outage rates and duration of outages are a function of variables that differ from one transmission business to another. For example, bush fire outages have had a significant impact upon the statistics in NSW in some years whereas cyclones would have a more significant impact in Northern Queensland. Different voltage levels have intrinsically different outage rates and the mix of voltage levels varies from one transmission entity to another.
Monitoring a number of these kinds of indicators over time will provide regulators, acting on behalf of customers, with a reasonable level of assurance that the risk of transmission service failure is not deteriorating due to inadequate investment, or declining standards of operation and maintenance.
Appendix 1 of this report sets out a more complete set of indicators used by the various transmission service providers.

Monitoring Code Voltage Quality Requirements

To meet Code requirements on voltage quality the following indicators could also be reported annually:

  • the number of measured excursions on the steady state voltage levels outside the limits in the NEC (this is largely a matter for NEMMCO)

  • the estimated demand and energy lost as a result of voltage excursions outside the standard.

  • the number of complaints regarding voltage quality received by the transmission TNSP.

  • the number of complaints regarding voltage quality validated by measurement.

  • the proportion of the valid complaints that were attributable to the transmission network.

  • the number of unresolved transmission complaints regarding voltage quality.

  • the number of transmission connection points monitored for voltage quality.

  • a report on any locations monitored where voltage quality did not comply with the standard in the NEC (with derogation’s where appropriate).

The Role of Planning Criteria

To ensure that investment decisions lead to acceptable levels of transmission service, planning criteria are used by transmission network service providers. Appendix 2 of this report summarises current world practice in relation to equipment redundancy. Appendix 3 summarises the service constraints that need to be addressed when developing a transmission network.

To the extent that the NEM Code does not already prescribe these criteria they ought to be accepted as defining good industry practice. In this way regulators will have criteria to assist in gauging whether investment levels are appropriate when setting revenue caps.

Transmission Service Requirements

A full due diligence assessment of the TNSP service obligations under the National Electricity Market is beyond the scope of this report. This is a legal process requiring consideration of all existing good practice obligations that still have standing following the proclamation of the National Electricity Law. However, it is clear that the NEM Code requirements are central to future TNSP obligations.

NEM Code requirements

Contrary to commonly articulated views the NEM Code does prescribe many measurable aspects of transmission service. These are largely set out in Chapter 5 but may need to be read in the context of definitions and obligations elsewhere in the Code. These obligations together with relevant Code references are summarised in the following sections.

Parties to Whom Transmission Service Obligations Apply

NEM Code imposes obligations on TNSPs to Network Users and defines Network Users as follows:

Network Users: Generator, Transmission Customer, Distribution Customer (ie. end user)
Transmission Customer: Customer, Non-Registered Customer, Distribution Network Service Provider having a connection point with a transmission network.
Obligations to ensure quality and security (NEMMCO has the lead role in security) of supply to Network Users (including end users) prevails over matters agreed in connection agreements (Sections 5.2.2 (d) and 5.2.3 (b) (3)). The Code definition of Network User unambiguously includes all end use customers. Performance standards must measure the degree of compliance with this obligation.
Accordingly TNSPs have obligations to each of the following groups:


  2. Market generators

  3. Market customers

  4. Direct (or nearly direct) connected end use customers

  5. Other TNSPs

  6. Distributors

  7. End use customers at large

(It would actually be useful to develop this section by analysing the precise nature of TNSP obligations to each customer group in turn. For example obligations to generators appear to be limited to negotiating connection agreements and access arrangements ‘in good faith’. By way of contrast there seems to be a requirement for transmission and distribution to develop their networks ‘as one’ to ensure the most efficient overall delivery of network services to customers as well as negotiating connection agreements)
National Electricity Code Provisions for Reliability
This section describes the obligations of the Network Service Provider (TNSP) in respect of reliability under the National Electricity Code (NEC). It should be noted that whilst the NEC lacks objective measures of network reliability, under [Clause 8.8], NECA is obliged to establish a Reliability Panel which must develop reliability standards.
Chapter 5 of the NEC sets down design and planning standards for transmission networks. Development of reporting requirements for reliability is one of the functions of the Reliability Panel [Clause 8.8.1].
The NEC [Clause 5.2.3 (b)] requires TNSPs to comply with power system performance standards in [Schedule 5.1] and in accordance with the relevant connection agreement, except where there is a conflict between these.
[Clause 5.2.3 (d)] requires the TNSP to manage, maintain and operate “its networks to minimise the number of interruptions to agreed capability at a connection point” by using “good electricity industry practice”. It also requires the TNSP to restore “the agreed capability as soon as reasonably practicable following any interruption at a connection point”.
[Clause 5.3.6 (c)] requires that offers to connect will comply with [Schedule 5.1 and as applicable Schedules 5.2 and 5.3] while [Clause 5.3.6 (e)] allows the TNSP to offer terms and conditions which vary from those contemplated in the NEC, provided they are “reasonable and are explicitly identified in the offer to connect”.
[Clause 5.6.2] requires the TNSP to analyse the performance of the network, identify any relevant technical limits which may be exceeded, notify and consult with affected Code Participants and analyse options to meet the technical requirements of [Schedule 5.1].
[Clause 5.6.2] outlines the process for the TNSP to initiate the relevant augmentation.
[Schedule S5.1] of the NEC describes the planning, design and operating criteria that must be applied by TNSPs to the networks they own or control.
Some of these requirements refer to levels of capability and quality for the common good of all, or a significant number of Code Participants. Others refer to requirements at an individual connection point. It allows for the requirements under a connection agreement with a particular Code Participant to be varied from those specified in the NEC, provided this does not adversely affect other Code Participants.
Network Reliability
[Schedule S5.1.2] requires an TNSP to plan, design, maintain and operate the network to allow the transfer of power from generating units to Customers with all power system facilities and equipment in service (called “the satisfactory operating state”).
A TNSP may be required by a Code Participant, under a connection agreement, to continue to allow the transfer of power with certain facilities or plant out of service, whether or not accompanied by the occurrence of certain faults (called “credible contingency events”).
Credible contingency events for transmission networks include : the disconnection of a single generating unit or transmission circuit with or without a single two phase to ground fault for lines operating at or above 220kV, and a single three phase fault on lines operating below 220kV.
[S5.1.2.2] requires the connection agreement to include the power transfer capability.

  • in the “satisfactory operating state”

  • during the most critical single element outage.

In the latter case, the power transfer capability may be in the range from zero up to the normal power transfer capability, according to the requirements of the Code Participant.

System Stability
[Clause S5.1.8] requires the TNSP to plan and operate the system so that, when in a satisfactory operating state, and following a credible contingency events:

  • the power system will remain in synchronism

  • damping of oscillations will be adequate

  • stable voltage control is achieved

Under the NEC damping is considered adequate if, after the most critical credible contingency event, the halving time of the least damped electromechanical mode of oscillations is not more than five seconds.

The NEC voltage control criterion is that stable voltage must be maintained following the most severe credible contingency event.
This clause also requires the TNSP to consider “non credible” contingency events and, where severe disruption is likely, the TNSP and/or Code Participant must install emergency controls to minimise disruption.
Appendix 1 – Examples of Performance Measures Used by TNSPs

1. International Examples

1.1 United Kingdom
In the United Kingdom, the Office of the Electricity Regulation (Offer) requires all licensees of transmission (or distribution) systems to report annually on their performance in maintaining system security, availability and quality of service.
It is understood that the recently formed NECA Reliability Panel will be using the UK reporting framework as a starting point in its deliberations.
The following are reported for each transmission utility annually or monthly as listed below. A five year history of each transmission company is presented:

  • the number of incidents when there was a loss of supply to one or more customers because of faults on the transmission system (annually).

  • the average amount of energy that is not supplied for incidents when there was a loss of supply to one or more customers because of faults on the transmission system (annually).

  • the time for which transmission circuits are out of service, planned or unplanned (monthly and annually).

  • the reason for transmission circuits being out of service in four categories; transmission system maintenance, transmission system construction, user connection to the transmission system, transmission system faults (monthly).

  • unavailability of transmission system interconnectors at the geographic boundaries of the transmission systems (annually).

1.2 New Zealand
TransPower New Zealand Limited in New Zealand publishers an Annual Quality Performance Report. The performance indicators in the report use the concept of a System Minute.
One System Minute is the amount of energy used during one minute at the system annual maximum demand; for example, in a system with a maximum demand of about 5000 MW, one system minute would be equivalent to 83MW hours. By the time the system maximum demand has grown to 6000MW, one system minute will be equivalent to 100MW hour. The system minute concept is used so that the severity of interruptions used as an indicator will keep pace with the size of the system.
Information required to be reported for The Electricity (Information Disclosure) Regulations 1994 is in two categories:

  • Energy Delivery Efficiency Performance Measures and Statistics

  • Reliability Performance Measures to be disclosed by TransPower.

Under the Reliability Performance Measures the following are reported annually:

  • Total number of unplanned interruptions.

  • Electricity customer interruptions in system minutes - total, planned and unplanned.

  • Underlying (see below) electricity customer interruptions in system minutes - total, planned and unplanned.

  • Average supply reliability - measured by the energy supplied divided by the sum of the energy supplied and not supplied.

  • Uneconomic generation due to planned and unplanned transmission system unavailability.

  • Uneconomic generation due to HVDC system unavailability.

  • Uneconomic generation due to unplanned transmission system unavailability.

  • Planned interruption restoration performance.

  • Unplanned interruption response.

The following are also reported:

  • non delivery of electricity in system minutes (see below) annually and monthly. The performance is divided into underlying levels which are losses of one system minute or less and significant losses which are those greater than one system minute. Losses of energy caused by generators or distributors are not included.

  • these annual supply losses are then categorised as followed :

  • environment - lightning, storm, volcanic ash, wind, tree contact etc.

  • equipment

  • human - the public, plane/boat/motor vehicle/etc contact, technician/operator error.

  • not known

  • miscellaneous - causes not covered by the above

  • planned - outages placed for maintenance, replacement or refurbishment

The availability of HVAC circuits is reported by presenting the following annually :

  • the number of circuit forced outages by voltage

  • the number of circuit forced outages per 100 route km

  • the number of circuit forced outages duration by route km

  • Comprehensive reporting of the HVDC link performance.

  • The number of losses of supply to customers by duration compared with performance from previous years.

  • The average number of interruptions per point of supply per year compared with performance from previous years.

  • The annual number of forced outages and the unserved energy for each supply point.

2. Existing Australian Practices for Monitoring of Transmission Performance
This section describes existing indicators used for reporting on reliability with Australian TNSPs.
Indicators which are reported internally, or which could be reported are outlined here.
Interruptions to service at individual connection points:

  • the total number of unplanned circuit outages which resulted in loss of supply (per year)

  • the frequency of loss of supply per connection point (incidents per connection point per year)

  • the minimum, maximum and average duration of loss of supply per connection point (minutes per connection point per year)

  • the amount of electricity not supplied per connection point per year (MW and MW hours per connection point per year)

Interruptions in the shared transmission network affecting multiple connection points :

  • the total number of unplanned circuit outages (per year)

  • the total number of unplanned circuit outages which resulted in loss of supply (per year)

  • the energy not supplied during each incident (MW hour)

  • the maximum load lost during each incident (MW)

  • the time taken to restore all load for each incident (hours)

(Note that the term “shared network” is not used in the NEC. It is used here to aid clarity to indicate those parts of the network that are used by a number, if not all, participants and to distinguish it from “connection” which serves one participant).

For some years, Australian TNSPs have reported transmission reliability against a target unsupplied energy measured in system minutes. A system minute is the energy used in one minute at the level of system annual maximum demand.
A single indicator based on system minutes has limited use as an indicator of performance. The system minutes for a reporting period could be made up of a large number of minor events or a few significant events, and could vary over a wide range without indicating any change in reliability.
The following basket of reliability indicators could be considered:
For individual connection points:

  • the frequency of planned interruptions (number per year)

  • the frequency of unplanned interruptions (number per year)

  • the duration of planned interruptions (hours)

  • the duration of unplanned interruptions (minutes or hours)

  • the quantity of electricity not supplied during interruptions (MW and MW hour)

  • the period of notice for planned interruptions (hours or days).

For the shared network:

  • the frequency of disturbances which result in interruptions (number per year)

  • the severity of the disturbance measured by the load not supplied - maximum MW and total MW hours

  • the time taken to restore all load

Circuit availability:

  • the aggregate proportion of time transmission circuits are available

3. Monitoring Voltage Quality Performance
3.1 United Kingdom
OFFER UK (source - Report on Distribution and Transmission System Performance 1995/96)
Incidents when the voltage went outside the limits of variation set out in the Electricity Supply Regulations and Grid Codes are reported annually. No statements as to the actual limits are made in the reporting arrangements.
3.2 New Zealand
No reporting was made on the quality of the voltage delivered in the TransPower New Zealand Limited Quality Performance Report 1995/1996.
3.3 Existing Practices for Monitoring of Voltage Quality in Australia
There are differences in the way in which transmission and distribution utilities deal with quality of supply issues. Transmission utilities tend to be focused on the standards required to be met and adopt a preventative approach by incorporating these standards into the planning phase. The sheer number of connections made at the distribution level would make this approach unworkable. This difference in approach makes the monitoring mechanisms applied by distribution and transmission utilities quite different.
The steady state voltage magnitude and level of voltage fluctuations are not monitored specifically by Australian TNSPs having been taken into account in planning the network. However, mechanisms are typically available via the SCADA systems to receive alarms if the voltage at any busbar goes outside pre-set values. These alarms are set inside the operational voltage limits to allow for measurement errors and corrective action if necessary. These alarm levels are normally set well inside the code limits of +/- 10%.
Potential harmonic levels and negative phase sequence levels are taken into account in planning the network, but are also monitored regularly, especially where potential problems are known to exist. The frequency of monitoring depends on the results of previous monitoring and changes to the network that have the potential to impact monitored levels. Reporting is done internally to assess whether compliance with the limits is being met.
3.4 Reporting Requirements for Voltage Quality
This section suggests a regime for reporting performance against the voltage quality standards. Its focus is on the impact on customers rather than costly routine surveillance.
A customer complaints system has been considered and in some cases mandated by Jurisdictional licensing arrangements. As customers normally deal with a retailer the majority of complaints would be directed to that retailer. The retailer would either deal with it or pass it on to the distributor, who would likewise either deal with the complaint or pass it on to the transmission TNSP. Due to the preventative measures undertaken by Transmission TNSPs most complaints regarding quality of voltage would result from the distribution level.
The following indicators may be reported annually:

  • The number of excursions in the steady state voltage levels outside the limits in the NEC (although this measure may relate to NEMMCO’s performance)

  • The estimated demand and energy lost as a result of voltage excursions outside the standard

  • The number of complaints regarding voltage quality received by the transmission TNSP

  • The proportion of these complaints where the cause is on the transmission network

  • The number of unresolved transmission complaints regarding voltage quality

  • The number of transmission connection points monitored for voltage quality

  • A report on any locations monitored where the voltage quality did not comply with the standards in the NEC (with derogations where appropriate).

Appendix 2 – Transmission Network Service Provider Planning Criteria Survey
A survey of the criteria used in power system planning in various countries was carried out. The survey was done on an informal basis during technical discussions at the CIGRE session 1998 in Paris 29th August - 4th September 1998.
The survey encompassed a total of 15 countries. The attached table summarises the results of the survey.
Each country uses criteria which are a consequence of the historical power system development in that country and are best suited to its unique conditions. However, the following general points can be summarised:

  • Most of the countries at present use deterministic criteria.

  • Majority of the planning groups are putting extensive efforts in developing techniques and software, and collecting data to adopt probabilistic planning criteria.

  • For the main grid - Most countries (N-1) criteria with some selected (N-2) contingencies.

  • For the major cities - Most countries either use (N-2) criteria or (N-1) with some selected (N-2) contingencies which commonly include two (2) cables buried in the same trench or a double circuit line.

  • All countries regard main cities which are commercial centres as well as 'seat of government' as critical for supply planning and tend to use (N-2) criteria.

  • Almost all engineers acknowledged the difficulty in the market environment where approval of proposed grid augmentations is in the hands of a regulator. More often than not regulators will not approve a criteria more stringent than (N-2) whereas customer and participant acceptance of rare losses of supply is not present, at least when it actually happens.

Appendix 2 – Transmission Network Service Provider Planning Criteria Survey (Ctd)




Planning Criteria Used







(N-1) Mainly but

(N-2) for defined contingencies






Advance techniques are in place



Grid and main cities

Dutch Electricity Board

(N-1) Mainly but

(N-2) for identified scenarios

No immediate plan for probabilistic criteria



Main grid

Furnas Centrais Electricas SA

(N-1) mainly but

(N-2) for some cases

Probabilistic planning is being gradually implemented



Main Grid



(N-1) For main grid

(N-2) for Tokyo

Only used internally in TEPCO to assess the extent and probability of load shed



Grid and major cities

North East Power Coordinating Council (NEPCC)

(N-2) for main grid and major cities

Moves are underway to officially adopt probabilistic criteria



Grid and major cities

Western Power Coordinating Council (WPCC)

(N-1) Generally but

(N-2) for a few defined contingencies

Appendix 2 – Transmission Network Service Provider Planning Criteria Survey (Ctd)




Planning Criteria Used





Main Grid
Major Cities

Scottish Power

(N-1) for main grid

(N-2) for major interconnectors

(N-2) for three hours, all major loads supplied continuously

In near future



Main grid and major load areas

National Grid, UK

(N-2) For main grid and major load areas containing more than 1500 MW demand

Probabilistic planning is being gradually implemented



Main grid and major cities

ESB/National Grid

(N-2) For selected contingencies and for load above a certain figure. More or less in line with UK

As above. Sophisticated techniques are being devloped


South Africa

Main grid


(N-1) For main grid to identify alternatives

Probability based analysis of alternatives using value of unserved energy



Main grid

Power Grid Corporation

(N-1) for main 500kV grid



Main grid and KL


(N-1) mostly but

(N-2) as deemed appropriate



Main Grid

Major cities

Israel Electric Corp

(N-1) for main grid

(N-2) for major cities and for defined scenarios



Various provincial Boards

Nothing definite could be ascertained

Appendix 3 – Transmission Network Planning Criteria and Performance Constraints

It is part of the transmission planning process to ensure that the power system is planned in such a way that it is capable of operating safely and efficiently under all system contingencies that have a comparatively high probability of occurring. Planning criteria and performance standards have been developed by supply authorities to assist in this. While these may vary from authority to authority, a great deal of commonality is generally found. The general intent of these criteria have also been embodied in the National Electricity Code.

Historically, planning criteria and performance standards were derived from several sources. These include legal requirements, Australian and International Standards, Statutory obligations, ESAA (in Australia and NZ) Guidelines and Codes of Practices, international practices, and local practices and requirements.
When investigating the need for reinforcing the transmission system the following constraints are generally considered:

  • Voltage limits

  • Plant ratings

  • Fault Levels

  • Unbalanced load

  • Quality of supply

  • Reliability and adequacy of supply

  • Stability criteria and analysis

Voltage Limits

Voltage levels on the main transmission system are generally held between ±10% of nominal under all operating conditions and this requirement has been encompassed in the NEC. Equipment voltage ratings and performance specifications dictate the upper limit of voltage. The lower limit can be determined by the ability to control customer voltages at nominal levels with depressed voltages on the transmission network. However, on some parts of the network it may not be possible to permit voltage levels to fall by 10% due to reactive power requirements. Under such circumstances a more stringent limit is imposed.

Plant Ratings

The maximum current carrying capacity of plant and equipment installed on the system is generally determined by thermal constraints or by safety and clearance requirements. In planning the development or augmentation of the transmission system it is important to ensure that the plant rating is not exceeded under any operating condition.

Some electrical equipment such as transformers, cables, and overhead lines have short term and/or cyclic ratings which are higher than the continuous rating assigned to the plant. This is because thermal time constant of the plant, which is related to the mass of the item and its surrounds, and the cyclic nature of the load. These short-term ratings may be utilised when operating the network.

Fault Levels

The plant and equipment installed on the power system is designed to withstand fault currents up to specific levels. Generation and load increases as well as network augmentations tend to increase fault levels on the system. The power system is planned, augmented, and operated in such a manner that the fault capability of plant is not exceeded.

Unbalanced Load

Three-phase electrical equipment is designed to operate on a symmetrical supply system. Certain items of plant such as electric motors and power electronics are intolerant of an unbalanced power supply or negative phase sequence. For this reason, negative phase sequence is limited to a low value (refer to NEC) and this is typically achieved by transposing transmission lines, use of specialised voltage control equipment, load balancing on the lower voltage network, and through the use of delta - star transformers which mitigate load unbalance on the high voltage winding.

Quality of Supply

AS 2279-Disturbances on Mains Supply Networks (parts 1-4) specifies the limitations of harmonics and voltage flicker permitted on the supply network. At transmission levels this is given as 3% total harmonic distortion (2% maximum for odd and 1% maximum for even harmonics) and the “threshold of perceptibility” for voltage fluctuations which has a maximum value of 4½% based on a single disturbance in a 24 hour period.

Reliability and Adequacy of Supply

Traditionally the reliability and adequacy of supply at a point on the transmission system have been assessed in a deterministic manner. This has typically been done by using the N-1 criterion that states that a proportion (normally 100%) of the peak load at that point on the network will be supplied with any single item of plant on the network out of service. Minor variations on this theme have occurred with alterations to the proportion of peak load to be supplied and the interpretation of what constitutes a single item of plant (eg. in a double circuit transmission line). Some supply authorities have also extended their reliability criterion to include second contingency events.

In recent years there has been a shift toward the use of probabilistic techniques for assessing network reliability. While a great deal of research has been done on this topic it is presently not in widespread use for power system planning purposes. This is possibly due to the variability of actual reliability figures over time and the relatively poor correlation these have to calculated values. Where probabilistic methods have been used to date this has commonly been in conjunction with deterministic methods with the deterministic methods being used to identify the need for a development and probabilistic methods used to assign a priority and a relative benefit to the project.
While not a simple process per-se, it is practical to ascertain that a networks fundamental design meets the N-1 reliability criteria at any point in time. However, it is much more difficult to determine how well a network performs against probabilistic criteria without obtaining a great deal of historical data and averaging actual performance information over a long period.

Stability Criteria and Analysis

To ensure that the system remains stable it is necessary to design and operate the system in such a way that it can withstand credible system contingencies that have a comparatively high probability of occurring. The following planning criteria have historically been used in this area:

  • system instability will not result from the application of a 2 phase to ground fault at the most critical location on the transmission system or for any three phase fault on the sub-transmission network cleared by primary protection.

  • the system would withstand the removal from service of any single item of plant for any reason without,

  • the decay of system oscillations exceeding a halving time of 5 seconds,

  • the loading levels of remaining plant exceeding their 15 minute thermal rating,

  • voltage levels falling by more than 5% on the main transmission system,

  • resulting in the shedding of customer load other than interruptible.

  • frequency levels will remain controlled within acceptable limits following conceivable contingency events on the system.

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