Guide to electricity network design and planning – part 1

This is part 1 of a three-part guide aimed at qualified engineers and/or graduates who are beginning their career in an electricity distribution network planning department, or perhaps moving into a planning role after some years in a different role (for example operations, maintenance or construction).

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Oct 02, 2017
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The focus of this article is on distribution rather than transmission planning. Nevertheless, the general principles are essentially similar, and since the distinction between the two is becoming increasingly blurred given the proliferation of distributed generation and energy resources, planning engineers new to either discipline should find the three parts of this guide useful. Part 1 covers the general principles of network design and planning, security of supply, network design basics, voltage management, load forecasting, electrical losses, and analysis and modelling. It includes a useful 21-point check list which planning engineers may find useful when preparing proposals for network investment.

The two complementary parts of this guide are:

  • Part 2 – which covers legislation and regulation, quality of supply, engineering recommendations and technical reports, investment appraisal, low carbon transition, and innovation and smart grids; and
  • Part 3 – which covers the basics of protection and overall protection schemes.


The engineering management of an electricity distribution or transmission system can be thought of as covering three timeframes: investment planning, operational planning and real-time operations. This document focuses on the first of these three timeframes. The role of the ‘planning’ engineer within a transmission or distribution company, or indeed a consultancy offering such services to a distribution network operator (DNO) or transmission owner (TO) is crucial to the satisfactory design and ultimate operation of the electricity system.

Legal frameworks, transmission and distribution code requirements, transmission and distribution licence obligations, and regulatory performance incentives will be discussed either later in this document or in complementary documents, but there is one fundamental obligation which is worth mentioning up front, which is the distribution and transmission code objective to ‘ permit the development, maintenance and operation of an efficient, co-ordinated and economical system for the distribution and transmission of electricity’ . This obligation fundamentally defines the responsibility of the ‘planning engineer’ whose decisions at the ‘investment planning’ stage of an overall network development strategy, or any specific project, will determine the capability of the electricity network which is then built and connected to the wider electricity system to support this objective.

That said, the task of developing an efficient, coordinated and economical system is not getting any easier. Indeed, the definition of ‘efficient, coordinated and economical’ is open to interpretation depending on the perspective of those who need to connect to, use, or are otherwise affected by the system, which includes various classes of consumer, developers, generators, Suppliers, community energy managers, local authorities, landowners, preservation groups, Government, Ofgem and numerous other stakeholders. It is for that reason that effective stakeholder consultation is now an essential input to the development of the power system.

What is now increasingly important is that the test of ‘efficient, coordinated and economical’ is applied to the whole of the electricity system, and not simply to the individual components. That means taking into consideration both transmission and distribution, and the overall real-time operation of the whole electricity system. Moreover, the ‘system’ isn’t just transmission and distribution; it also includes generators in all their guises, energy storage, and indeed the customer’s installation which is set to become an increasingly active component of the system, facilitated by smart meters and the internet. Given the emerging need for coordination across all energy vectors to address Britain’s energy trilemma (which can be summarised as a need for affordable, secure, and low carbon energy) increasingly the test will need to be applied to the whole ‘energy’ system.

This guide is arranged in three parts and its purpose is to provide qualified engineers and/or graduates who are beginning their career in a network planning department, or perhaps moving into a planning role after some years in a different role (e.g. operations, maintenance or construction) with sufficient guidance to know where to start and (importantly) where to look for further information and more detailed guidance. In that respect, a number of sources of information are referenced which provide far greater depth than this guide can possibly cover. It is therefore incumbent on new (and indeed experienced) planning engineers to make themselves familiar with the content of these sources of information, and refer to them whenever it is appropriate to any study they are undertaking. The focus is on ‘distribution’ rather than ‘transmission’ planning. Nevertheless, the general principles are essentially similar, and since the distinction between ‘T&D’ is becoming increasingly blurred given the proliferation of distributed generation (DG) and energy resources, planning engineers new to either discipline should find the guide useful.

Electricity system topology

Before getting into the detail of the network planning role it would be useful first to reflect on the overall topology of the GB electricity system and, in particular, more recent developments in terms of sources of electricity production and their impact on network power flows.

Fig 1 provides a very generalised depiction of the GB power system. In practice there are variations on topology. For example, direct 132/11kV transformation (by-passing 33kV) is now common across parts of the distribution systems, particularly those operated by UK Power Networks and Western Power Distribution. Moreover, across GB as a whole, there are significant numbers of networks operating at 6.6 or 6kV (as an alternative to 11kV). Similarly, there are many examples of 275kV transmission (particularly in urban areas) in lieu of 400kV, and 66kV in lieu of 132kV. There are also examples of 22 and 20kV networks, albeit the former tend to be ‘traditional’ alternatives to 33kV whereas the latter can be either legacy systems or ‘modern’ alternatives to 11kV. In terms of points of connection, again Fig 1 is representative but by no means definitive. For example, onshore wind and solar photovoltaic (PV) farms might be connected at 132, 33 or 11kV, and some offshore wind farms are connected into the onshore system at 132kV (which is legally classed as ‘distribution’ in England and Wales and ‘transmission’ in Scotland).

Fig 1: High-level schematic representation of the GB power system

Source: Millhouse Power

The key message that emerges from Fig 1 is that there are now many sources of infeed into the power system, ranging from offshore wind farms, EU interconnectors, DG and energy storage, and microgeneration connected as part of consumers’ electrical installations. This results in power flows that can vary, not only in magnitude but also in direction, to a far greater extent than envisaged when the system was originally planned. These new power flows represent a significant challenge to the design of the power system, and a key aspect of the planning engineer’s role is now to understand their impact on plant thermal ratings, voltage regulation, power quality, and protection systems.

General principles of system planning

The core of a planning team’s role is to scrutinise the electricity system for loading, security of supply, reliability, voltage regulation and power quality, operational facility, environmental impact and overall efficiency (which includes losses). This extends to considering the potential impact on any of the above of a requested new or increased capacity connection to the system, for example a new industrial or housing development, or a DG scheme, or an existing customer with an increased import or export requirement.

That in turn leads to a need for the planning engineer to ensure that schemes to provide network reinforcement, asset replacement, quality of supply improvement, environmental risk mitigation, improved flexibility or efficiency, or a new or increased capacity connection, are formulated in good time to avoid an unacceptable deterioration in system security or performance, or a delay in connecting a new source of demand or generation.

Crucial here is the need to understand lead times in respect of: securing planning permissions and consents, procurement, construction, arranging planned outages and availability of outage windows, and testing and commissioning. In particular, a need to secure rights for new substation sites and, for schemes involving overhead lines, rights to install assets across third-party land, can sometimes require detailed submissions (including environmental impact assessments) protracted negotiations and, in extreme cases, public inquiries. Indeed, the elapsed time between finalising the design of a major scheme and the final commissioning of the project can be typically one or two years for a major distribution project, or a few to several years for a transmission project.

A key point for a planning engineer to understand is the need to take both a holistic and long-term view when considering the overall development of the network. Particularly under times of pressure (perhaps due to a high level of new connection requests) it is all too easy to become ‘reactive’, responding to one particular driver for network investment rather than taking a broader view. For example, there will often be potential synergies in terms of network benefits arising from: reinforcement to increase network capacity, security, or efficiency; and asset replacement to improve network reliability, quality of supply or environmental performance.

The most cost-effective schemes are those which deliver the highest benefit/cost ratio taking all of the benefits and costs into account, and not necessarily the ‘least cost’ scheme to meet a specific requirement or resolve a particular issue. An effective technique to apply here is that of ‘incremental cost-benefit analysis’ which systematically considers the value of incremental levels of investment above a base case. This is explained in more detail in the section on Investment Appraisal in part 2 of this guide.

By the same token, the planning engineer should consider not just the immediate, but the long-term needs of the network when considering investment. Several things are necessary here:

  • Systematic and accurate load forecasting taking into account local authority development plans, projected economic growth and new-build forecasts – all of which will ultimately translate into new demands on the electricity system.
  • Asset condition information and network performance data which might indicate adverse trends and hence the need for future intervention.
  • Specific pipeline proposals in respect of new industrial, commercial and housing developments that will impact the network under consideration.
  • Similarly, prospective DG developments including CHP, solar PV and on-shore or offshore wind farms, or grid-scale electrical energy storage schemes that might result in higher and/or reversed power flows on parts of the distribution system, potentially extending to periods of export from distribution to transmission networks at grid supply points (GSPs), but also potentially providing network constraint management facilities.
  • Any cost-effective opportunities to improve long-term efficiency (e.g. reduced electrical losses) or network performance (e.g. through system automation, active network management, enhanced protection, etc.).
  • Any other pressures which are likely to require future interventions to the part of the network under consideration, such as the need to address reliability (e.g. parts of the network susceptible to severe wind storms or vulnerable to flooding); environmental performance issues (e.g. poor condition oil-filled cables); or public safety concerns (due, say to proximity of overhead lines to areas of recreational activity).

It follows from all the above that the planning engineer has a need to establish and maintain effective liaison with many other roles within the organisation such as: load forecasting teams, operational consents teams (or wayleaves officers), procurement teams, asset managers, control centre and operations staff, outage planners, construction and commissioning teams, environmental and safety managers, and connections teams. Similarly, the distribution planning engineer must establish effective external liaison with local planning authorities, street works authorities, developers, prospective generators and community energy managers, other network and system operators, other utilities, and key stakeholders such as the Environment Agency, to enable the creation of strategic regional network development plans and long-term development statements (LTDS) 1 .

Most companies will have teams dedicated to wider stakeholder consultation which will typically include industrial, commercial and domestic customer representative groups, suppliers, transport authorities, the Country Landowners Association, the NFU, local MPs, and Government departments such as BEIS and DEFRA. These stakeholders will help shape companies’ longer term strategic business plans.

Having established the basics of network planning, we will now begin to describe some of the principles in more detail, as well as the more common tools and techniques available to the planning engineer to enable him or her to fulfil the requirements of their role. Having determined that some form of intervention to the power system is required (e.g. due to a new connection, general load growth or an asset renewal need) the planning engineer must produce a detailed scheme to address the requirement. Whilst every scheme will be unique in some way, there are common principles and practices that generally apply.

Most companies will have established practices (e.g. Prince2 project management methodology) and quality assurance procedures which must be followed. Major projects will generally require a sequence of ‘stage gate’ reviews and it is important that planning engineers understand precisely what is required at each gate stage, including any final post investment evaluation.

The following section provides a useful summary of the things that a planning engineer should consider when faced with a need to prepare a new scheme.

Planning engineer’s check list

The following is a suggested ‘21-point check list’ that an engineer new to a planning role might find useful as a reference when confronted with a need to prepare a scheme:


Have you got the facts – all the facts and have you identified the real problem?


For new or additional loads, have you received details of any special features such as high starting currents, harmonic injection, phase imbalance, etc.?


For schemes involving generation or energy storage, have you established the impact on fault levels, the intended modes of operation and/or capacity factors (e.g. for weather dependent generation) and their temporal impact on system power flows?


Has the necessary modelling been undertaken to assess (as appropriate to the scheme) load flows, voltage profiles, power quality impacts, stability, fault levels, etc.?


Have you used the latest prices for labour and materials (including contractors’ rates) and are there any unusual construction aspects that warrant a departure from standard estimating schedule rates?


Have you established whether there are any factors that might justify a higher (or lower) than normal level of design security or reliability – for example a particular need for supply continuity or an abnormal exposure to wind storms or flooding?


Have you considered alternative schemes which might offer a cheaper solution or deliver additional benefits (e.g. lower system losses)?


Is the timing right; could some or all of the work be deferred without unacceptable risk?


In the case of a scheme requiring major reinforcement at 132kV have you considered whether a new exit point (i.e. a new GSP) or an additional supergrid transformer at an existing GSP might provide a more economic solution?


Have you considered ‘smart’ alternatives that might avoid or defer the need for major investment – such as demand-side response arrangements or export curtailment provisions (for generation), the scope for applying dynamic plant ratings, or other active network management techniques?


Are your proposals economically/commercially sound and supported by cost-benefit and sensitivity analyses where appropriate?


In the case of a scheme involving a new or increased capacity connection, are you satisfied that the ‘sole use’ and ‘shared cost’ elements of the new assets have been correctly identified in determining the customer’s contribution?


In respect of any new or increased capacity connection scheme, have you prepared the quote(s) in the timescales required by the regulatory standard appropriate to the proposed connection voltage, and have you liaised with connections teams to ensure the connections can be achieved in the timescales agreed with the customer?


In the case of a major scheme, are the proposals and costs broadly aligned with the company’s regulatory business plan submission and regulatory settlement?


Are you satisfied that the necessary deeds, consents and/or wayleaves are obtainable and in good time?


In cases where there may be issues with accommodating new circuits in existing highways or in obtaining road opening notices due to traffic congestion (e.g. in central business districts) have you initiated route feasibility studies?


Have you considered the construction outage risk (i.e. for major schemes such as a grid or primary substation replant) and included appropriate allowance for any required risk mitigation works?


Could the proposals have a material impact on power (or reactive) flows at the transmission/distribution interface and/or require reinforcement of the transmission system and, if so, has the TO been consulted?


Have you consulted with construction and commissioning staff who will be involved in delivering the project to obtain their input, and also connections, operations and asset management staff to determine whether there might be other factors such as impending new developments, network performance issues or asset replacement programmes affecting the part of the network under consideration?


Are the proposals supported by appropriate risk assessments and mitigation measures, and does the scheme make appropriate provisions for contingency?


In preparing your proposals, have you complied with the company’s certified internal quality assurance systems and procedures (e.g. as certified under ISO 9001, ISO 14001 and ISO 55000)?

If the planning engineer can confidently answer ‘yes’ to all the above (as appropriate to the scheme) then the chances are that the proposals will be essentially sound. Having covered these general principles, we will now start to look at some of the more important aspects of network design and planning in greater detail.

Security of supply

DNOs have a licence obligation to plan and develop their systems in accordance with a standard not less than that set out in Engineering Recommendation P2/62. Similarly, transmission licensees have an obligation to plan and operate their systems in accordance with the National Electricity Transmission System Security and Quality of Supply Standard (NETS SQSS) administered by National Grid. A detailed exposition of these standards is beyond the scope of this document but it is essential that planning engineers fully familiarise themselves with the requirements. In summary, the current standard, ER P2/6, sets out, for a range of classes of supply and demand groups, the minimum demand that must be capable of being met following a first and second circuit outage.

For example, for a group demand falling in the range >1 to 12 MW (supply class B) the distribution system must be designed so as to permit the group demand –1 MW to be met within 3 hours following a first circuit outage (the remaining 1 MW to be restored in the time required to effect repairs).

For a group demand falling in the range >60 to 300 MW (supply class D) group demand –20 MW must be capable of being restored immediately, with the remainder of the group demand being restored within 3 hours. For a second circuit outage, for group demands >100 MW, the smaller of group demand –100 MW and 1/3rd of group demand must be capable of being restored within 3 hours, with the remainder of the group demand being restored following restoration of the arranged outage.

Specific provisions are laid out for the remaining supply classes: A, C, and E covering a total range of group demand from up to 1 to 1500 MW. For group demands above 1500 MW (class F) the requirements are set out under NETS SQSS.

By way of some context for the above:

  • ‘Group demand’ is the sum of the maximum demands of the substations within the group, with any appropriate factoring for both diversity (i.e. if the substation maximum demands occur at different times) and the effect of DG.
  • ‘Within 3 hours’ is based on an assumption that restoration would be achieved through manual switching (i.e. not requiring a repair). However, the regulatory incentive on quality of supply (the interruption incentive scheme referred to in more detail in the section on quality of supply) has led DNOs to increasingly look to remote control and automation in order to achieve much faster supply restorations, particularly for faults affecting class B group demands (typically 11kV fault outages).
  • For class D, a supply restoration within one minute (e.g. through automation) is considered ‘immediate’; and for class E (>300 to 1500 MW) a loss of up to 60 MW for up to 1 min is permissible for a first circuit outage if this leads to significant economies.
  • A ‘second circuit outage’ is defined as a fault outage following an arranged outage. In other words, the provisions do not apply in the rare event of a second fault outage following a first fault outage (or two simultaneous fault outages) or indeed a busbar failure. The first circuit outage restoration requirements apply equally to either arranged or fault outages, though for supply classes C to F, consumers should not be interrupted by arranged outages.
  • An arranged outage (e.g. for maintenance or construction works) would normally be taken only at a time when the second (fault) circuit outage requirements could be met. So for example a maintenance outage affecting a Class D group of substations would be taken at a time when the actual demand was such that the ‘smaller of group demand –100 MW and 1/3rd of group demand within 3 hours could be met.

The examples above provide an overview of the requirements under ER P2/6 but it must be emphasised that the distribution planning engineer will need to be fully familiar with the requirements, or at least aware of where a copy of the Engineering Recommendation can be viewed. Moreover, the current industry review of ER P2/6 might lead to a number of fundamental changes in the way that security should be assessed and addressed.

Network design basics

HV and EHV network design

It will be apparent from the earlier section on security of supply that whilst ER P2/6 does not specifically define how the network must be constructed and configured, it nevertheless leads to a number of fundamental network design requirements. For example, it will be apparent that to meet the ‘within 3 hours’ restoration requirement for class B, the network (typically an 11kV feeder or possibly a small primary 33/11kV substation) there will need to some form of switched alternative. An 11kV feeder would therefore typically be arranged as a ring or have interconnections with one or more other 11kV feeders.

For a class C group demand >12 to 60 MW (typically a medium to large 33/11kV primary substation or a small 132/33kV grid substation) the requirement under a first circuit outage to be able to restore group demand within 3 hours, and group demand –12 MW or 2/3rd of group demand (whichever is the smaller) within 15 min, will generally require that the group demand is supplied by at least two normally energised circuits or one circuit with remotely or automatically controlled alternative circuits (e.g.11kV feeders which are able to transfer load to an adjacent primary substation by switching).

An alternative to duplicate or switched alternative circuits and transfer capacity permitted under ER P2/6 to provide required levels of design security, is the use of DG. Guidance on the contribution that can be assumed from various categories of DG under outage conditions is provided by an Engineering Technical Report ETR 130. The current review of ER P2 will take account of the contribution available from alternatives such as energy storage and contracting (typically with larger commercial customers) for demand side response (DSR) services.

Fig 2 is a schematic illustration of the topology of a typical mixed urban/rural distribution system serving a number of grid and primary substations. Notable in the diagram is the classic ‘transformer feeder’ arrangement whereby (generally) a pair of 33kV feeders serve one or more primary substations and, similarly, a pair of 132kV feeders serve a grid substation. Each feeder will usually have the capability to alone meet the maximum demand for that substation (possibly with the aid of transfer capacity to other substations) in order to be able to comply with the ER P2/6 first circuit outage supply restoration criteria for class C and D group demands.

Fig 2: Topology of a typical mixed urban/rural distribution system

Variations to the 33kV transformer feeder arrangement illustrated in Fig.  2 include the use of direct 132/11kV transformation serving an urban substation and a 33kV ring arrangement serving a smaller rural primary substation.

Fig 2 is broadly representative of a common approach to network design at the higher distribution voltages which will generally be found across Great Britain serving urban and rural distribution systems, whilst Fig 3 shows a configuration for serving major urban distribution systems based on direct 132/11kV transformation. Notable here is the common use of double-busbar 11kV switchboards.

Fig 3: Topology of a major urban distribution system

However, there are variations on these themes that will be encountered in parts of Great Britain, some of which can be explained by different legacy design philosophies between companies dating back to nationalisation (or even pre-nationalisation) days. For example, parts of Central London retain an LV interconnected HV system, the history of which can be traced back to pre-second world war days, whilst the Scottish Power ‘Manweb’ system serving Merseyside and North Wales retains a unique interconnected unit-protected EHV/HV system.

LV network design

Whilst SQSS and ER P2 design levels of security are the primary drivers for network design for Transmission and EHV distribution networks, with quality of supply performance now taking precedence over ER P2 for 11kV network design, the drivers for LV network design are quite different.

Fig 4 shows a typical configuration for an LV network serving a mainly residential area. One of the two LV feeders has an interconnection facility to an adjacent substation via a link box, providing limited backfeed capability to preclude the need for notified shutdowns when undertaking distribution substation or associated HV network maintenance.

Fig 4: Typical LV network configuration

Notwithstanding consideration of losses, this interconnecting cable will be sized sufficiently to make practical use of the ‘backfeed’ capability when the adjacent substation is de-energised. This facility would be provided only where justified by cost-benefit analysis.

For LV networks, the principal design requirements are:

  • Ensuring sufficient thermal ratings for the envisaged aggregate ‘after diversity maximum demand’ (ADMD) to be supplied by the distribution substation and individual LV feeders.
  • Ensuring voltage at all nodes of the network, and in particular at all service positions, is retained within statutory limits under maximum and minimum demand conditions.
  • Where microgeneration levels are such that export from generators is significant, maintaining voltage within statutory limits under maximum export and reverse power flow conditions.
  • Ensuring that fault levels are sufficiently high, and earth loop impedance sufficiently low, to ensure reliable substation fuse operation in the event of a fault.
  • Ensuring that prospective short circuit currents are within the short-time ratings of network components.
  • Ensuring that fault levels are sufficient to ensure that flicker (e.g. due to electric showers or in future heat pump starting currents) is contained within acceptable levels (see reference to Engineering Recommendation ER P28 later in this document).
  • Achieving an acceptable level of phase balance, especially when demand is approaching the ADMD for the network (see reference to Engineering Recommendation ER P29 later in this document).
  • Ensuring the optimum specification and sizing of network components (transformers, lines and cables) with respect to network losses.

Voltage management

There is a statutory obligation to maintain the (rms) voltage supplied to consumers within limits prescribed under the Electricity Safety, Quality and Continuity Regulations 2002 (as amended in 2009). For LV supplies the limits are 400/230 V +10/−6%. For all higher distribution voltages up to less than 132kV, the limits are ±6% of the ‘declared’ voltage. For supplies provided at 132kV or above, the limits are ±10%.

Voltage at supergrid, grid and primary substations is actively managed by automatic voltage control (AVC) schemes in conjunction with transformer on-load tap-changers. Determining and regularly reviewing ‘set points’ for AVC schemes is an important specialist area. As with protection, it is important that planning engineers advise operations staff responsible for AVC strategy of any significant network changes that may affect AVC settings.

In particular, the connection of DG might give rise to significant changes in the voltage regulation along the feeder it is connected to, and may require modifications to set points or even the overall AVC scheme 3 .

By way of a brief explanation, the underlying principle of AVC is to achieve a balance between maintaining system voltages at an ideal level (i.e. within statutory limits and with regard to minimising losses) and avoiding excessive numbers of tap change operations (which would have maintenance and plant life expectancy implications). This ‘ideal’ is achieved through a ‘bandwidth’ (or dead band) setting within which the voltage can vary without initiating a tap change, and through a timing relay so that transient voltage variations do not trigger a tap change operation.

Coordination of tap-changing between the hierarchy of system transformation levels (e.g. 400/132, 132/33, 33/11kV) is achieved through configurable time-delay relays, the objective being to allow the higher voltage transformer tap changers to operate before downstream lower voltage tap changers in the event of a system-wide voltage correction being required (e.g. as system load begins to build during the late afternoon/early evening period and then begins to fall off in late evening and throughout the early morning period).

The combination of dead band and time delay ensures that short variations in voltage which normalise after several seconds do not trigger a tap-change operation. The dead band also addresses the risk of ‘hunting’ – i.e. where a tapping-up operation then results in the initiation of a tapping down operation (or vice versa) after only a brief period.

The use of automatic tapchangers extends down the voltage hierarchy to primary substation (typically 33/11 or 132/11kV) transformers. 11kV/LV transformers are equipped with off-load tap change switches (or internal links for pole mounted transformers) and the tap setting for these is determined by their location on the system – i.e. those remote from the primary substation may have a higher tap setting to compensate for the voltage drop along the HV feeder.

In that regard, it is worth mentioning that in the case of rural primary substations, use is sometimes made of ‘line drop compensation’ which results in the primary substation 11kV busbar voltage being raised under high load conditions to compensate for the voltage drop along a long rural feeder.

It is possible that consideration might in future be given to relaxing the requirements at LV to 400/230 ±10% which would increase the scope of LV systems to accommodate microgeneration, heat pumps and electric vehicle charging. However, for the time being, the limits prescribed under the current ESQC Regulations must be respected. That might in turn mean that in some cases, active voltage control of LV networks might in future be required, either through the use of distribution transformers with on-load tapchangers or in-line voltage regulators.

Load forecasting

A core function of the planning department’s role is to understand, and plan for, network load growth (including potentially negative load growth). In particular, it is essential that the network will be able to accommodate future loads in terms of: plant thermal ratings, maintaining voltages within statutory limits, fault levels, power quality and ER P2 (or SQSS) design requirements for security of supply. A further consideration is the impact of future loads on network losses.

As mentioned in the section on General Principles of System Planning, crucial here is the need to understand lead times in respect of securing planning permissions and consents, procurement, construction, arranging planned outages and availability of outage windows, and testing and commissioning. This in turn means that proposals, and route feasibility studies where appropriate, need to be put in place in good time.

It follows that load forecasts looking forward a number of years will be important in order to assess the critical timing of any required reinforcement or other network intervention (such as DSR for example). Medium to long-term load forecasts need to be as granular as possible in order to understand the likely level of load growth at each point of the network – for example at least down to primary substation level and ideally 11kV feeder level, if not distribution substation level. Factors which will influence load forecasts for a distribution network include:

  • Overall regional economic growth.
  • Regional new-build projections.
  • Regional employment forecasts.
  • Local authority development plans.
  • Specific proposals by developers such as new housing or industrial estates (connections teams will generally be the best source of information here).
  • Proposed new generation such as wind farms, solar PV farms, waste-to-energy schemes, CHP plants, etc.
  • Proposed installations of grid-scale electrical energy storage.
  • Local authority or social housing initiatives such as installing rooftop solar PV generation, new heating systems (e.g. heat pumps to replace fossil fuel systems), domestic storage, or other energy efficiency initiatives.
  • Any specific initiatives around EV charging infrastructure.
  • Changes of use of existing commercial or industrial building stock that might impact network loadings.
  • Any proposals by TOs that might affect power flows or fault levels at GSPs.
  • And of course any adjacent network development proposals which will impact power flows on the part of the network under consideration.

The above is not an exhaustive list, and the planning engineer will need to remain alert to any factors that could impact load growth on specific parts of the network under his or her jurisdiction. Given the inherent uncertainty over economic forecasting and many of the factors outlined above, it will be important to understand the sensitivity of load forecasts to any variations in these factors. Typically, companies will produce a set of scenarios which might be simply based on overall levels of growth (e.g. high, medium, low) or more complex scenarios taking account of interdependencies between the various inputs. National Grid updates and publishes its ‘Future Energy Scenarios’ annually based on comprehensive research, and these are a useful reference source for both transmission and distribution planning engineers, particularly in terms of longer term forecasting (e.g. 10-years or more ahead).

Fig 5 illustrates a typical ISO 9001 process that a distribution planning department might follow in order to assess compliance with ER P2 of major substations under future load growth forecasts.

Fig 5: Typical demand forecasting and security risk assessment process for major substation sites

Referring to the ‘demand forecasting’ (left-hand side) part of the process in Fig 5 , most companies will have database systems such as Pi Historian for holding historic half hourly (or similar) data for voltages and feeder loadings down to primary substation 11kV feeder level4. This provides essential information in terms of overall trends in demand growth but also any changes in the seasonal or daily demand profiles.

This historic information coupled with future load growth scenarios and new intelligence enables planning load estimates to be prepared comprising various reports and, in particular, grid and primary substations forecast to be outside firm capacity within a few years. A further use of the analysis is to inform the Grid Code Planning Code ‘week 24’ submissions to National Grid. National Grid uses this information in the preparation of its annual Electricity Ten-Year Statement and as an input to their Future Energy Scenarios which are updated annually.

For sites where demand is forecast to exceed firm capacity, this information provides the required input to the second ‘security risk assessment’ part of the process taking factors such as thermal ratings and temperature rise calculations into account in order to quantify the level of risk. For example, it might be that a site is projected to be outside firm capacity for only a few days a year and then for perhaps only a few hours on such days. On the other hand, a large new point load might mean that the site will be outside firm capacity for several months of the year and for several hours a day.

An important part of the process will be to correct historic and projected demands for ‘average cold spell’ (ACS) or, for sites where summer demand is significant (such as central business districts with a high level of air cooling) ‘average hot spell’ (AHS) conditions.

Fig 6 shows the results of analysis showing the impact of daily average ambient temperature on both weekday maximum demand (in this case the 11kV current supplied by a single 11.5/23 MVA OFAF 5 33/11kV transformer under N –1 conditions) and transformer emergency cyclic rating at a primary substation site supplying a summer peaking demand. It will be observed that below around 12 °C, convergence between the demand and emergency cyclic rating curves is gradual, whereas above 12 °C, the convergence is rapid. Moreover, whilst there is ample firm capacity headroom under ACS conditions, under AHS conditions, demand is projected to exceed the firm capacity of the substation. Understanding this characteristic helps pave the way for applying real-time thermal ratings to transformers6.

Fig 6: Weekday maximum demand and transformer emergency cyclic rating under ACS and AHS conditions

The next part of the security risk assessment process would be to determine the annual energy at risk – i.e. the extent to which, and the period over which, demand will exceed firm capacity. This part of the security risk assessment process will determine the nature and scale of intervention required, for example whether one or more DSR contracts might provide sufficient risk mitigation, or whether major reinforcement will need to be put in hand.

The charts under Fig 7 illustrates typical summer and winter peaking annual demand profiles and firm capacities for primary substations serving urban and suburban areas, together with potential DSR dispatch events (i.e. in the event of a fault outage occurring during the period at risk). Note that transformer ratings, and hence substation firm capacities, vary inversely with ambient temperature and hence tend to be greater during the winter months.

Fig 7: Typical annual demand profiles for primary substations serving urban and suburban areas

Source: UK Power Networks

Electrical losses

The management of electrical losses has always been a consideration in the design of electric networks and the specification of electrical plant and equipment. Indeed, the optimisation of losses is one aspect of the design of an ‘efficient and economic’ system.

Forms of electrical losses

Electrical losses take a number of forms, the principal ones being:

  • ‘Variable’ or copper (Cu) losses which are due to electrical resistance of conductors and hence have a quadratic relationship with the current passing through the conductor (i.e. losses = I 2R).
  • ‘Fixed’ or iron (Fe) losses (also known as ‘no load’ losses) which are incurred as a result of the magnetising forces involved in transforming electricity. The main component is the hysteresis loss which can be thought of as the energy involved in continuously magnetising and demagnetising the transformer core (100 times per second for a 50 Hz AC system). The losses are ‘fixed’ in the sense that, unlike variable losses, the losses are not a function of the load current passing through the conductor (i.e. transformer windings); they are present and virtually constant so long as the transformer is energised, even when supplying no load7.
  • Other less significant forms of technical losses including: corona8, skin effect9, cable sheath and dielectric leakage losses (i.e. in conductors and insulators), ‘stray’ losses which relate to flux leakage from the intended magnetic path within the transformer core and eddy current10 losses (i.e. in transformer cores and windings).
  • Although not regarded as ‘losses’ per se, the energy involved in running network ancillary equipment such as transformer cooling fans and pumps (i.e. for OFAF transformers) which are required to dissipate the heat produced as a consequence of transformer losses, and other auxiliary energy supplies directly associated with electricity distribution (including substation heating, lighting, ABCB air compressors, tunnel cooling systems, etc.)

Benefits of reducing losses

Reducing losses to the most economic level has the following consumer and wider societal benefits:

  • It maximises the available capacity of plant and equipment to deliver useful energy (i.e. rather than supply losses).
  • By the same token, it also reduces the amount of generation required purely to supply network losses. In the case of variable losses, due to their quadratic relationship with current (i.e. variable losses are proportional to the square of the current passing through a conductor) a disproportionate level of less efficient (and generally higher carbon footprint) generation will be called upon to supply losses at times of peak demand (reducing reliance on the less efficient fossil-fuelled power stations therefore has a direct ‘carbon benefit’).
  • It follows from the above that if losses are minimised, then lower levels of capital and operational expenditure will be incurred in providing, maintaining and reinforcing generation, transmission and distribution assets (there is also a carbon benefit in terms of avoided material extraction, manufacturing and transportation costs).
  • A lower level of losses will result in lower resistance-induced voltage regulation along LV distributors and hence enable a wider effective voltage bandwidth to be deployed and/or a lower substation voltage set-point to be established – both of which will enable higher network capacity utilisation.

Typical distribution of electrical losses

Although there will be significant variations between regions depending on the urban/rural mix of the area served, and hence the network topology, for a distribution system, a reasonable working assumption is that typically around 30% of technical losses will be due to fixed losses and 70% due to variable losses. In terms of how these are distributed across a distribution network: some 55% of fixed losses will typically be due to HV/LV distribution transformers and 20% due to EHV/HV transformers. For variable losses, some 45% will typically be at the LV network level and 25% at HV (generally 11kV) level11. Overall, LV and distribution transformer losses typically account for around 45% of total distribution losses, and HV losses for around 25%. EHV losses (including 132/33kV transformers and other EHV/EHV variations) account for around 25% of fixed losses and 30% of variable losses, and 30% of losses overall.

Effective measures to reduce losses

All network companies will have a published losses management strategy which will provide a comprehensive description of the actions that will be taken to reduce losses to a level that is economically justified, taking into account the whole system benefits as outlined above. Planning engineers should therefore make themselves familiar with the company’s strategy, and ensure that appropriate consideration is given to losses minimisation, and that economic measures are incorporated within network design proposals. Some of the more cost-effective measures include the following:

  • Use of ‘low loss’ transformers – i.e. in respect of both copper and iron losses12.
  • Optimised conductor sizes – which at least at the lower voltage levels will generally mean a larger cross-sectional area of conductor than is necessary for thermal rating, voltage regulation or (at LV) loop impedance purposes.
  • Optimised initial loadings of transformers – which at least for HV/LV transformers will mean a higher electrical rating than is necessary for the demand served.
  • Optimising normal running arrangements – i.e. ensuring that normal open points on radial systems are ideally placed to minimise losses taking into consideration loading characteristics13.
  • Setting AVC systems and distribution transformer tap positions to optimise voltage levels.
  • Taking steps to correct power factor.
  • Ensuring balanced phase loading so far as is reasonably practicable.
  • Taking steps to control levels of system harmonics.
  • Minimising energy usage at operational sites14.

Analysis and modelling

Network companies will have a range of analysis and modelling packages to support the planning and associated activities described in this document. Fig 8 summarises the drivers for modelling capability and the types of analysis currently undertaken across investment planning, operational planning and (real-time) system operation timeframes.

Fig 8: Overview of current modelling capability of the GB system operator and network companies

The modelling packages of most direct interest to network planners will be those that address the requirements listed under Investment Planning. Several commercial packages are available to deal these requirements and will vary between companies.

Typical packages that a planning engineer might encounter include:

  • DigSILENT PowerFactory.
  • PSS/E.
  • PSS Adept/PSS Sincal.
  • IPSA.
  • DINIS.
  • WinDebut.
  • GROND.

Fig 8 is taken from an IET report commissioned by the Government Office of Science and the Council for Science and Technology (Energy), and is available for downloading from the IET website15. The report acknowledges the current modelling capability of the industry, but highlights several areas where further modelling capability needs to be developed in order to address the challenges foreseen due to:

  • Decarbonisation and decentralisation of electricity production.
  • Electrification of heat and transport.
  • Market evolution – new business models and more engaged customers.
  • A more actively managed and interoperable electricity system.
  • The step-increase in volumes of data required to manage the future system.


  1. [DNOs are required to publish these yearly as a requirement of their licences.]
  2. [ER P2 is from time to time reviewed and updated. At the time of writing, the current version – ER P2/6 – is the subject of an industry review.]
  3. [Modern voltage control relays such as Fundamentals’ Super TAPP n+ incorporate advanced control algorithms to allow wider temporal voltage variations due to DG to be managed]
  4. [Increasingly, distribution companies are beginning to develop systems for capturing data down to distribution substation level.]
  5. [OFAF – oil forced/air forced cooling – i.e. using fans and pumps to supplement natural (ONAN) oil cooling achieved through natural convection.]
  6. [A suite of documents under BS IEC 600076 provides guidance on calculating temperature rise and loading limits for power transformers.]
  7. [Note however that transformer iron losses do vary with core flux density. Nominal values for iron losses therefore apply only when operating at rated secondary voltage. Typically, a 1% increase in secondary voltage produces a 2.5% increase in iron losses.]
  8. [Corona losses are generally significant only in the case of EHV overhead line conductors. They result from break down in the air (insulation) surrounding the conductor due to very high voltage gradients.]
  9. [Skin effect describes the tendency of an alternating current to distribute itself within a conductor so that the current density near the surface of the conductor is greater than that at its core. The impact is to increase the effective resistance of the conductor giving rise to higher variable losses. Being a function of AC frequency the impact will be greater if harmonic currents are present.]
  10. [Eddy current losses are a function of variable losses in a transformer but also vary with the square of the frequency. Hence the presence of harmonics in the transformer windings will have a proportionally greater impact on the eddy current loss component.]
  11. [This apportion includes variable losses on the associated lower voltage windings of transformers.]
  12. [An EU directive specifies the minimum efficiency (‘Ecodesign’) requirements for small, medium and large power transformers.]
  13. [Particularly for 11kV systems, quality of supply performance may be the dominant consideration for determining NOPs]
  14. [Although not strictly ‘losses’ in the sense that consumption at major substations is generally metered and entered into settlement, it nevertheless represents a system efficiency improvement opportunity.]
  15. [‘Developing Challenges for the Modelling of Electricity Systems’ – December 2015:]
Go to the profile of Dave Openshaw

Dave Openshaw

Director, Millhouse Power Limited

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