The Costs Benefits of Embedded Generation in Ireland
Cost and Benefits of Embedded Generation in Ireland
September 2004
Report prepared for Sustainable Energy Ireland by:
PB Power
CONTENTS
1.
2.
3.
4.
5.
6.
Executive Summary
1.1
Representative Networks
1.2
Costs and Benefits Methodology
1.3
Stakeholder Views
1.4
Recommendations for the Irish Market
Introduction
Review of Perceived Costs and Benefits of Embedded Generation
Part A – Technical Issues
3.1
Utilisation of Network Assets
3.2
System Losses And Overall System Efficiency
3.3
Security And Quality Of Supply
3.4
System Reinforcement Costs
3.5
Impact of embedded generation on reinforcement plans
3.6
System Control, Load Balance And Safety
3.7
Commercial Implications
3.8
Financial Implications
3.9
Other Issues
3.10
Considerations for Micro- and Small Scale Embedded Generation (SSEG)
Representative Network Identification and Modelling
4.1
Electricity distribution in Ireland
4.2
Topographical analysis
4.3
Power system modelling
Power system studies
5.1
Purpose of studies
5.2
Effect of embedded generation on network performance
5.3
Effect of embedded generation on low density 110/38/10 kV rural networks
5.4
Analysis of 110/38/10 kV semi-urban networks
5.5
Analysis of 110/38/10 kV dense urban networks
Embedded Generation Benefit Calculation methodology
6.1
Introduction
6.2
Approach
6.3
Key to symbols
6.4
Connection Methodology Functional Overview
6.5
Least Cost Technically Acceptable Solution (LCTAS) Process
6.6
Connection Offer Dispute
6.7
Displaced Energy Benefit
6.8
Loss Benefit Calculation
6.9
Voltage Benefit Calculation
6.10
CML Benefit
6.11
Asset Benefit
6.12
Transmission Benefits
6.13
Emissions Benefit
6.14
Social Benefit
1
2
5
7
8
11
13
15
16
19
22
22
23
26
28
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31
33
33
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99
101
102
107
111
115
120
129
136
143
150
156
161
7.
8.
9.
6.15
Fuel Benefit
6.16
Example Calculations
6.17
Issues of note
6.18
Methodology Findings
Market Survey
7.1
System Charges
7.2
Trading Arrangements
7.3
General Market Issues
Stakeholder Views
8.1
Stakeholder Questionnaire
8.2
Response from Stakeholders
8.3
Analysis of stakeholder responses
8.4
Key findings of stakeholder survey
Treatment of Costs and Other Issues Related to Connection of Embedded
Generation
9.1
Purpose
9.2
International Review
9.3
Recommendations for Irish Market
9.4
Next Steps
Appendix A – Terms of Reference
Appendix B – Topographical Analysis
B.1
Objectives and Methodology
B.2
Sample of Network Types
B.3
Network Topography
B.4
Derivation of system model
Appendix C – Network Studies
C.1
Power system studies of representative 110/38/10 kV rural network
C.2
Power system studies of representative 110/38/20 kV rural network
C.3
Power system studies of representative 110/38/10 kV semi-urban network
C.4
Power system studies of representative 110/38/10 kV dense urban network
Appendix-D – Example Calculations
Appendix E – Stakeholders Questionnaire
Addendum - Costs and Benefits of Embedded Generation
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298
1.
Executive Summary
To achieve Ireland’s commitment of supplying 13.2 percent1 of its electricity from energy based on renewable
sources by 2010 will present significant challenges to the whole industry. The fundamental technical differences in
the characteristics and sizes of typical embedded generation power plants when compared to conventional central
power stations will present specific challenges for the design and operation of existing medium voltage distribution
networks. Connecting significant amounts of embedded generation to passive electricity distribution networks will
require the distribution utility to adapt in order that a continued safe, reliable and efficient source of electricity is
ensured.
In addition to the technical issues, the EC Renewables Directive (2001/77/EC) and the Electricity Market Directive
(2003/54/EC) place obligations on Member States and their network operators in terms of their treatment of
embedded generation. This extends to the dispatch, energy pricing and accounting for the contribution that
embedded generation makes to distribution network security and reliability.
To assist with the formulation and implementation of future Irish Government policy for the period after the
proposed market liberalisation in 2005, Sustainable Energy Ireland (SEI) commissioned PB Power to undertake a
detailed study on the costs and benefits associated with the connection of embedded generation in the Irish
electricity distribution network.
The principal objectives of the study2 have been to:
a.
Perform a detailed assessment of the costs and benefits to all parties involved in the connection of
embedded generation to the electricity networks, including analysis of generic sections of the Irish
electricity distribution network;
b.
Propose procedures that can be used to identify the costs and benefits of connecting specific types and
sizes of embedded generation to the Irish electricity distribution network;
c.
Review and analyse the commercial considerations put in place by other jurisdictions to facilitate the
connection and the technical and commercial operation of increased levels of embedded generation;
d.
Poll the views and opinions of the key Irish market participants with interests in the development of
embedded generation. The participants approached included the CER, ESB National Grid, ESB Networks
and a representative sample of prospective generation developers and independent supply companies.
Issues explored ranged from the treatment of embedded generation, the implementation of EC directive
2001/77/EC in Ireland and the implications of the proposed move to market liberalisation through the
adoption of a centralised wholesale market.
e.
Propose options for allocating the costs of connecting embedded generation fairly and equitably between
all of the parties involved.
1
Target from EU Directive 2001/77/EC
2
The Terms of Reference for the Study are included within Appendix A to this report.
-1-
1.1
Representative Networks
The bulk of the ESB distribution network is located in rural areas and is likely to remain so for the foreseeable future,
even with continued growth of the Irish economy and the resulting expansion of the area of urban and semi-urban
development, particularly in areas within reasonable commuting distance (i.e. 100 km) of Dublin.
The rural distribution network is characterised by long, single circuit overhead lines, configured as a radial network at
either 10 kV or 20 kV, to supply an area of low load density, with densities typically in the range 20 kW/km2 to
50 kW/km2. At the other extreme, in central Dublin, electricity distribution is via 38 kV and 10 kV underground cable
networks that supply customers in high load density areas, with densities typically in the range 5,000 kW/km2 to
10,000 kW/km2. In the larger towns and on the outskirts of Dublin and the other cities where there is a mix of
domestic, commercial and light industrial loads the load density is typically in the range 1,000 kW/km2 to
4,000 kW/km2.
Following a review of ESB Networks’ rural, semi-urban and dense urban networks in Ireland, five principal network
types are considered to capture the characteristics that typify the electricity distribution network in Ireland. These
five representative network types are:
Type 1 - 38/10 kV rural,
Type 2 – 38/20 kV rural,
Type 3 – 110/20 kV rural3,
Type 4 – 38/10 kV semi-urban,
Type 5 – 38/10 kV dense urban.
To determine principal physical characteristics for each of the representative network types, topographical analysis
was undertaken on fifteen high voltage and sixty medium voltage network circuits. These networks were selected
from areas where there is a reasonable expectation of future development of embedded generation based on the
availability of sustainable energy resources. Raw data for the analysis was in the form of the ESB Networks single line
diagrams for the 38kV network, geographic layouts of the medium voltage distribution network, substation and
feeder loads, transformers, overhead line and cable data. The principal characteristics reviewed in the analysis were:
3
•
Primary substation and feeder voltages
•
Type of network (i.e. overhead or underground)
•
Installed primary substation and distribution transformer capacity
•
Load supplied (or load density)
•
Area of supply
•
Feeder physical characteristics (i.e. numbers and lengths of trunk, spurs and stub circuits)4
•
Voltage control facilities.
The analysis presented in this report has been limited to determining the effects of embedded generation specifically on the distribution network.
Consequently power system studies of the 110/20 kV network type have not been undertaken. Although the principles for system modelling and
power system studies presented in this report can be similarly adopted to examine the effects of embedded generation with respect to the 110 kV
system, the model of the transmission system would have to take account of load and generation despatch.
4
ESB Networks, in common with utilities elsewhere, use standard conductor sizes for their overhead line and underground cable networks.
Consequently there is a degree of commonality with regard to conductor types and sizes across the various network types.
-2-
The sample networks analysed were located in the counties of Donegal, Leitrim, Kerry and Kildare5. The analysis
included one of the Midlands networks to determine whether there is a significant difference between rural
networks in the west of Ireland and networks in the Midlands. The analysis of semi-urban networks was based on
data for an area outside central Dublin. The analysis of dense urban networks was based on data for a part of the
10 kV distribution network in Central Dublin.
The power system studies have been undertaken using industry recognised load flow software incorporating the
physical characteristics determined for the representative networks. These studies have concentrated on
determining the impact the embedded generation has upon the steady state operation of the distribution system
with a range of generator capacities and connection points with the distribution network6. The representative
network single line diagram for the semi-urban 38/10kV network is shown below to illustrate the various connection
points used for the embedded generation in the power system studies.
In particular, load flow and short circuit analysis has examined the effect that increasing levels of embedded
generation in the high voltage and medium voltage networks will have on the following:
a)
Circuit and equipment loading - to identify when connection of embedded generation influences the
requirements for reinforcement of the network compared with base case conditions;
b)
Technical losses – to identify the effect that connection of embedded generation has upon the
distribution system technical losses. Specifically whether they increase or reduce as a result of the
connection of the generator;
c)
Voltage and voltage control requirements - to determine the effect that connecting embedded
generation will have on the representative network voltage profile;
d)
Short circuit levels – to determine the effect that connection of embedded generation to the network will
have on system fault level and the likelihood of the local distribution network switchgear rating being
exceeded.
5
The number of networks in our sample was necessarily limited. There are obviously other counties and areas of rural Ireland that have similar
potential for sustainable energy type developments that could equally have been included in the sample.
6
There are other concerns associated with the dynamic performance of the generator and the network that are not addressed here. The study of the
dynamic performance would require specific modelling of frequency and voltage control devices of generation and is therefore considered at this
time a site-specific issue.
-3-
Figure 1-1 Representative Network used Semi-Urban 38/10kV Analysis
-4-
The key findings of the power system studies showed that :
Connection of embedded generation directly onto the MV substation bus bar effectively reduces the
110kV power import by the same amount;
Significant loss savings can be realised by connecting the generation near to the mid point of the outgoing
MV trunk feeder. In the case of the 100/38/10kV rural representative network there was an optimum
generator size of between 3 to 3.5MW, above which the embedded generation begins to increase system
losses;
For voltage benefits to be realised on the MV network the embedded generation should ideally be
connected at, or close to, the mid point of the MV trunk. In the case of the 110/38/10kV representative
network this removed the need for voltage booster transformers;
In the longer term embedded generation provides an offset to technical losses, voltage support
requirements and potential overloads that would otherwise be evident due to system load growth. This
will effectively allow offset of capital expenditure on voltage support and system reinforcement;
1.2
Costs and Benefits Methodology
The intent behind the calculation methodology is to propose a mechanism that accounts for the full range of costs
and benefits from connection of embedded generation to the Irish electricity distribution network.
The
methodology has taken a holistic approach to the calculation of the costs and benefits and incorporates benefits
that have a more country-wide impact. Further, the calculations are projected over a 15-year period in order to
capture longer term benefits from the embedded generation operation. The proposed method is split into elements
to aid visibility of the assumptions, input data sources and calculation formulae. The elements7 considered are:
Energy Price Benefit - The connection and operation of embedded generation plant within the distribution
network will affect the operation of transmission system connected generation plant due to system
demand being reduced through the embedded generation offsetting local system demand. The purpose
is to assess the extent of any differential in the cost of generation between the embedded generation and
the cost of providing the energy from a system generation plant;
Energy Loss Benefit – This determines the value of the embedded generation impact on the distribution
system losses. It is likely that there will be a positive benefit through the reduction in peak system capacity
required to service the distribution network demand and reduced cost in terms of annual energy loss as
the load is being supplied locally;
Voltage Benefit (including Reactive Power provision) - This determines the value of the embedded
generators impact on the distribution system power factor and voltage support. It calculates a benefit
value arising from any avoided / deferred capital expenditure due to improved power factor and any
saving in the cost of reactive energy required by the distribution system.
7
Note that in the context of this list, “benefits” incorporates negative benefits i.e. costs.
-5-
Customer Minutes Lost (CML) Benefit - This determines the value attributable to the impact of the
embedded generation on the distribution system reliability and security of supply through increased DUoS
charge revenue to ESB Networks and improved service levels to customers;
Asset Benefit - This determines the benefit on the basis that the embedded generation defers the need to
replace assets either as a result of reduced thermal loading or releasing network capacity that can be used
to support load growth in future years. The asset benefit related to reduced system peak losses is
accounted for within the Losses calculation process.
Transmission Benefit - This determines the value of the embedded generators impact on the transmission
system through from reduced losses and capital expenditure deferment due to changes in the timing of
system reinforcement;
Emissions Benefit - This determines a value for any benefit from reduced environmental emissions due to
displaced system generation plant. The emissions considered are CO2 (EU ETS costs), NOX and SOX.
Social Benefit – The determines the value of any social benefits that will derive from the installation of the
embedded generation. This is driven by the impact of the embedded generation on local jobs and other
sources of income.
Fuel Benefit - This determines the quantity of fuel that is saved / displaced as a result of the embedded
generation operation. This will be derived from the avoided system plant and the embedded generation
operation profile. This is represented in terms of kWh pa of fossil fuel input avoided.
The example calculations undertaken use the power system study results for a 2.5MW embedded generator
connected into various points on the 38kV section of the 110/38/10kV rural reference network. The assumed LCTAS
connection cost for both plant was €250,000 which was used to offset the benefits calculated. The impact of the
generator reliability has been ‘flexed’ by running the calculation for a Wind generator and a CHP generator, as shown
in Table 1-1 below.
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Table 1-1 Benefits for Embedded Generation - Example Calculations
Connection Point
Wind Generation
CHP Generation
Total Benefit
Fuel Benefit
Total Benefit
Fuel Benefit
Mid Trunk
€4,941,887
21,900,000kWh
€5,903,976
8,591,539kWh
End Mid Trunk Spur
€2,918,553
21,900,000kWh
€2,774,174
8,591,539kWh
End Trunk
€3,052,487
21,900,000kWh
€2,921,776
8,591,539kWh
5km 38kV Feeder
€2,788,545
21,900,000kWh
€2,592,548
8,591,539kWh
(totals over 15 years)
The results of these example calculations8 have shown that:The value of the loss benefits is very sensitive to generator location on the network due to the contribution
from the avoided energy losses with connection at the mid point along the trunk being the best location ;
The value of the displaced energy is dependent on having access to a suitable long term operational
profile for the generation plant and the resultant load factor on the system;
The elements contributing most value all include energy related components (Displaced Energy, Loss
Benefit and the Transmission Benefit) ;
Asset based benefits will require access to auditable capital expenditure plans for the distribution network
and the ability to discriminate between load related and voltage related capital expenditure;
The value of the CML benefit is marginal;
The scale of the benefits is significant as they have been projected across a fifteen year time horizon;
The recognition of the various benefits will need to be made either on a cash basis through offsetting
connection costs or on a societal basis similar to the arrangements under the Public Service Obligation that
support the social generation plant.
1.3
Stakeholder Views
The views of key stakeholders in the Irish electricity market were polled using a structured questionnaire.
Unsurprisingly, a wide range of differing views was expressed. These are analysed briefly below.
There was a general acknowledgment of the need to reduce commercial uncertainty in order to encourage
increased deployment of embedded generation. Developers’ underlying concern was the bankability of projects,
rather than on what the market mechanisms are per se. Compensation or protection from the variations in a large
market pool was a key theme. Other respondents were more concerned with ensuring market mechanisms provide a
level playing field for all generators. A separate, predictable support mechanism outside the market might best meet
the range of needs expressed.
Costs of connection and reinforcement associated with new embedded generation connections clearly need to be
allocated in some manner, although existing deep connection charges are viewed as a discouragement to
8
Refer to detail provided in Section 6.16.
-7-
embedded generation by most generators. Repayment of costs over a number of years might mitigate this,
effectively converting the upfront capital cost into a form of DUoS charge. Allocation of part of the costs to other
beneficiaries of the reinforcement would also encourage embedded generation.
There were differing views on flexibility of generation. While the proposed market arrangements would encourage
generators to be more flexible, it was pointed out by some that wind is inherently inflexible – due to resource
intermittency, it cannot always choose when to generate (although it can choose when not to). There is therefore a
concern that wind may be disadvantaged as thermal plant makes itself more flexible.
On the treatment of losses, there was a general desire for a more transparent means of calculation and allocation. An
underlying theme was to avoid general limits or definitions that would result in some embedded generation causing
losses and not being charged, and vice versa.
The question of location pricing divided respondents between those who believe that it would discriminate against
wind generation (where the best resource is often in remote areas where Location Marginal Price is low), and those
who believe that all generators should receive price signals related to location. However, there was general
acceptance that only generators above a certain capacity should receive Location Marginal Price, while those below
would receive the wholesale system price. Since the survey of opinion was conducted, CER has set this limit.9.
1.4
Recommendations for the Irish Market
A number of international markets have been reviewed to identify any novel approaches implemented to provide
support to embedded generation through recognition of the benefits that it is able to provide to the electricity
distribution system (and to a lesser degree the transmission network). The general situation appears to be that
tariffs and connection policies are focused on minimising the impact of embedded generation and large demand
customers on the distribution network due to the need to maintain security of supply and standards of supply
quality.
In general there does not appear to be any strong evidence for pro-active support for renewable and CHP
generation within the charging structures for connection and use of the distribution and transmission systems10.
Germany appears to provide the most pro-active support through the provision of feed-in tariffs at the transmission
level which filter through to the generation users in the form of offset payments made to them by the distribution
companies.
Within the Irish market the benefits could be treated in the following way:
•
Loss Benefit - Recognition of this could be through applying an uplift to the generator distribution loss
factor that represents a share (say 85%) of the avoided system loss. This uplift could be applied for a
defined period of time, say 5 years, after which the uplift is incorporated into the embedded generators
loss factor and is removed from ESB Networks’ allowable revenues. This calculation is best undertaken by
ESB Networks;
9
Limit is at a maximum export capacity of 5 MVA. See CER/04/214, “Implementation of the Market Arrangements for Electricity (MAE) in
relation to CHP, Renewable and Small-scale Generation”, 9th June 2004
10
Most support schemes focus on providing support on an electricity generated basis, i.e. per kWh
-8-
•
Asset Benefit - The deep connection charging could be replaced with shallow charging (dedicated
connection assets only) and a generator DUoS charge levied on the exported energy from the embedded
generation site. These DUoS charges could then provide locational signals related to the potential to avoid
capital costs. This calculation is best undertaken by ESB Networks and would benefit from provision of a
regular distribution network planning statement;
•
Voltage Benefit - The reactive energy production from the embedded generation plant should be
assigned a value and payments should be made on the basis of metered reactive power production or
consumption. Any payments made by the distribution company to embedded generators would be on
the basis of the reactive power charge within the published DUoS tariff for the connection voltage level.
This calculation is best undertaken by ESB Networks or the metering and settlement agent in the MAE;
ESB Networks should be encouraged to make best use of the capability of embedded generators to
provide voltage support ‘on-demand’ to the distribution network. This will need to be taken into account
during the connection process;
•
Transmission Benefit - this benefit should be paid by the DNO on an annual basis as an offset against
ongoing connection charges levied on the embedded generator. The amount would be directly
proportional to the embedded generators contribution to the reduced capacity requirement at the
transmission-distribution interface. This calculation is best undertaken by ESB Networks;
•
Energy Benefit - To the extent that there is a positive benefit arising from the displacement of energy (i.e. the
cost of the displaced system plant energy is greater than the cost of the embedded plant energy), the benefit
should be passed through to the end customer as a reduction in the energy tariff applied by ESB PES to the
customer energy sales. This calculation could sit within ESB Supply or ESB NG;
•
Emissions Benefit - the emissions benefit can be seen as a mechanism by which the PSO support for the
alternative energy requirements is reduced as the embedded renewable generation plant will be able to source
revenue to support their business from emission trading. This would prevent a windfall crystallising in favour of
the embedded generation plant and serve to reduce the overall cost to the end customers;
•
Fuel Benefit – this benefit will be seen within the long term Irish economy. It is not seen as being a benefit that
feeds through directly to the embedded generator;
•
Social Benefit – this benefit is realised within the community local to the generator through construction and
operation and maintenance.
•
Micro and Small Scale Embedded Generation - standardised connection terms could be applicable for microand small-generation plant below a de-minimis level11. These standardised connection terms might provide a
sliding scale of standard connection charges for such generation linked to the generator capacity and
incorporating the costs and benefits associated with typical import/export profiles for this class of customer.
11
For example, 100kVA, which has been set by CER as the limit for exemption from MAE rules (CER/04/214).
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NEXT STEPS
Following the above analysis and suggestions for the Irish market, it is suggested that a number of areas be explored
further.
•
Examine the potential benefits of establishing ‘Active Network Areas’ to provide incentive on the DNO to
partner with embedded generation and/or responsive demand connections to investigate the potential for
alternative distribution network control mechanisms;
•
Determine the level of system security support that can be attributed to embedded generation, the
process to determine this and the value of the avoided / deferred cost of network capital expenditure;
•
Determine the impact and value of introducing an element of ‘Non-firm’ capacity to the connections for
embedded generators and the operational controls that would need to be implemented to control the
capacity used;
•
Investigate the present costs for islanding schemes and the validity of the ESB Networks prohibition on
establishing islanded portions of the distribution network;
•
Seek to have ESB Networks publish a distribution network statement to provide detailed information on
the development plans for the distribution network and the opportunity areas for generation and/or
demand location. Such a statement would have information relating to network fault statistics, CMLs, in
addition to the capacity available and fault levels on the network;
•
Study the possibility of establishing an incentive within the ESB Networks regulatory formulae to
incentivise investment in technology and mechanisms that reduce the overall system losses. This should
provide a notional allowable value to losses such that benefit can be derived by ESB where they manage
the network with losses below the target amount.
•
Determine the process to ensure that any deferred capital expenditure or loss benefits are recycled to the
appropriate party and accounted for within the LCTAS connection process or under regular payments;
•
Determine the appropriate capacity cut-off level for standard connection terms and costs to facilitate
connection of micro- and small-scale embedded generation to the distribution network;
•
Undertake independent assessment of the impact on ESB Networks’ operational costs were elements of
the embedded generation calculation methodology to be adopted within the LCTAS connection process;
Examine the potential for utilising embedded generation to provide local Ancillary Services within the
distribution system. This would include provision of Black Start, Reactive Compensation Services etc and would
need to determine the technical capability of the technology and the cost of any specific control equipment
necessary to enable the service (both within the DNO and the generator).
- 10 -
2.
INTRODUCTION
The connection of a significant amount of embedded generation to existing electricity distribution networks poses a
series of challenges that need to be overcome to ensure a safe, reliable and efficient source of energy. In addition to
the technical issues, the EC Renewables Directive 2001/77/EC places obligations on Member States and their
network operators in terms of:
•
open access to networks for energy from renewable sources
•
preferential despatch from renewable sources; and
•
a non-discriminatory charging policy with respect to energy from renewable sources.
Further the EC Electricity Market Directive 96/92/EC (as repealed by Directive 2003/54/EC) requires that:
•
Despatching of generating installations be determined on the basis of criteria that must be “objective,
published and applied in a non-discriminatory manner” (Article 8.2);
•
“Distribution system operators shall procure the energy they use to cover energy losses and reserve
capacity in their system according to transparent, non-discriminatory and market based procedures”
(Article 14.5);
•
“When planning the development of the distribution network, energy efficiency/demand side
management and / or distributed generation that might supplant the need to upgrade or replace
electricity capacity shall be considered by the distribution system operator” (Article 14.7).
The Irish electricity sector is also in a period of transition as the market moves away from its previous monopolistic
state and works towards full liberalisation through the introduction of a centralised wholesale power pool. This
change in trading arrangements imposes an extra layer of complexity on the resolution of technical, commercial and
economic issues surrounding the connection of embedded generation. However, the introduction of the changed
trading arrangements will provide smaller generators ready access to the market to obtain prices equal to that which
other generators will receive.
To achieve Ireland’s commitment of supplying 13.2 percent of its electricity from energy based on renewable
sources by 2010 will present significant challenges to the whole industry. Additional to the fundamental technical
differences in the characteristics and sizes of typical embedded generation power plants, compared to conventional
central power stations, challenges will arise because the majority of this new capacity will be connected to existing
medium voltage distribution networks. To further exacerbate the problems associated with the connection of
embedded generation, it is likely that wind turbine generators will provide most of the embedded generating
capacity. Wind turbines provide an intermittent source of generation that can present new challenges to which
conventional distribution system operational practices will have to adapt.
To assist with the formulation and implementation of future Irish Government policy for the period after the
proposed market liberalisation in 2005, Sustainable Energy Ireland (SEI) commissioned PB Power in September 2003
to undertake a detailed study on the costs and benefits associated with the connection of embedded generation in
the Irish electricity distribution network.
- 11 -
The principal objectives of the study are to:
a.
Perform a detailed assessment of the costs and benefits to all parties involved in the connection of
embedded generation to the electricity networks, including analysis of generic sections of the Irish
Network. This aspect of the study is presented in sections 5, 6 and 7 of the report.
b.
Propose procedures that can be used to identify the costs and benefits of connecting specific types and
sizes of embedded generation to actual sections of the Irish electricity network. These proposals are
discussed and presented in Section 8 of the report.
c.
Review and analyse the commercial considerations put in place by other jurisdictions to facilitate the
connection and the technical and commercial operation of increased levels of embedded generation. This
analysis in Section 9 of the report.
d.
Ascertain the latest opinions of CER, ESB National Grid, ESB Networks and a representative sample of
prospective generation developers and independent supply companies in relation to the treatment of
embedded generation, the implementation of EC directive 2001/77/EC in Ireland and the implications of
the proposed move to market liberalisation through the adoption of a centralised wholesale market. The
discussion and presentation of views on the issues is presented in Sections 3 and 4 of the report.
e.
Establish the options for allocating the costs of connecting embedded generation fairly and equitably
between all of the parties involved. The options are identified in Section 9 of the report.
A copy of the Terms of Reference for the study is presented in Appendix A.
-12 -
3.
Review of Perceived Costs and Benefits of Embedded Generation
In this section we identify the potential costs and benefits that can be obtained from the connection of embedded
generation to the distribution network. A qualitative analysis is undertaken to identify where this results in a cost or
a benefit to the Developer, to ESB Networks (the Distribution Network Operator or DNO), to ESB National Grid (the
Transmission System Operator or TSO), or to some other third party.
We have examined the impact of connecting embedded generation to the distribution system in relation to what we
view as the critical issues, embracing the technical, economic and financial sectors. The areas covered are listed in
Table 3.1 overleaf. The qualitative review of the associated costs and benefits for each of the items in Table 3.1 is
presented below – split into between those items that are regarded as ‘Technical’ (Part A) and those regarded as
‘Commercial / Financial’ (Part B).
It should be noted that certain costs and benefits associated with embedded generation can be difficult to ascertain
and it is noted that efforts are underway to clarify these. Where this is the case the issues have nevertheless been
identified, albeit without any firm indication of the associated costs or benefits.
-13 -
Table 3-1 Costs and Benefits of Embedded Generation
Issue
Contributory Elements
Utilisation of Network Assets
Asset Life and Utilisation
Effect on System Planning
System Losses and Overall System Efficiency
Treatment / Allocation of Losses
System Operation Costs
Security and Quality of Supply
Voltage Regulation
Availability and Quality of Supply
Voltage Waveform Quality
Security of Supply
System Operation Costs
System Reinforcement Costs
Effect on Fault Levels
Network Planning Cost and Resources
Avoidance / Deferred Reinforcement
Possible delay in reinforcement
Impact of Generation location on Load Flows
System Control, Load Balance and Safety
Islanding
Reactive Power Flows
Displaced Loads
Network Constraint and Load Management
Commercial Arrangements
Avoidance of TUoS Charges
Displaced Load
Capital Cost of Plant
Connection Costs
System Operation Costs
Wind Power forecasting
Financial Implications
Reduction in fuel consumption
Reduction in emissions
Avoidance of Carbon Trading Costs
Indigenous Fuel Supply Security
Social Benefit of Green Energy sales
-14 -
Part A – Technical Issues
3.1
Utilisation of Network Assets
The life of a distribution system asset is determined by a number of factors, notably; the duty it has performed, the
standard of maintenance it has received and the number of major faults on neighbouring assets that it has endured
during the course of its operational life. It is well known that the life of assets that have a thermal rating, such as
transformers, cables and overhead lines12 is related to the temperature at which they operate and the operating
temperature is related directly to the current flowing through the asset’s conductors, i.e. its utilisation.
The nominal life of an asset is determined by its normal operating regime. However, on occasions when an asset is
overloaded for one reason or another, this may cause the insulation material to age prematurely in cables and
transformers such that the asset life is reduced.. However, when the same asset is operated below its normal loading
this tends to reduce the ageing process and may extend its life.
One of the results of operation with embedded generation connected to the network is that it can reduce demand
on cables and transformers connected upstream of the generator and so prolong the life of the upstream assets.
The distribution system owned and operated by ESB Networks operates at the following voltage levels:
a)
110kV13 and 38 kV High Voltage (HV) distribution,
b)
20 kV and 10 kV Medium Voltage (MV) distribution,
c)
380/220 V Low Voltage (LV) distribution.
The capacity of embedded generation that can be connected at each voltage level is limited by factors such as short
circuit level14, allowable voltage change that would result from the sudden disconnection of the embedded
generation and the thermal loading and rating of existing circuits and equipment. As a general guide for a typical
rural network an indicative capacity for the connection of embedded generation at the HV, MV and LV voltage levels
is 10 MW, 2 MW and 200 kW respectively. On the other hand a typical urban network can accept about double the
capacity of the typical rural network with 20 MW, 5 MW and 400 kW indicative capacities for embedded generation
at the corresponding voltage levels15.
Examination of a number of typical rural MV networks in the west of Ireland revealed that the majority of renewable
energy schemes (involving wind farms and small hydro plants) are connected directly to the local HV/MV primary
substation at 10 kV or 20 kV via a dedicated circuit. This type of connection for embedded generation will have
minimal effect on utilisation of the downstream network, but in the more remote rural areas, where voltage
regulation is a problem, the embedded generation will provide some voltage support to the local area. The
upstream network will, however, generally benefit from the connection of embedded generation through lower
12
With the exception of switchgear these are the main current carrying elements of a distribution network.
13
The 110kV distribution network is within the area of the Dublin.
14
In particular the amount of headroom available between the existing short circuit level and the switchgear rating (or more realistically a 5 percent
margin below the switchgear rating).
15
This is referenced to PB Power’s report to ETSU on the “Costs and Benefits of Embedded Generation”, dated February 2000.
-15 -
network utilisation. The new generation will, depending on its capacity, be able to supply part, or all of the local load
and, if of sufficient capacity, even part of the upstream load.
The effect on system utilisation of an alternative connection arrangement, based on “teeing-in” the embedded
generator to an existing network circuit, is more difficult to assess, it being very much site specific and dependent on
factors such as the existing network arrangement, the location and capacity of the embedded generator and the
location and size of the load. In this type of connection arrangement the effect of the embedded generator on the
utilisation of the network will be variable and it is conceivable that, whilst utilisation on some parts of the network at
the connection voltage level may fall, utilisation on other parts of the network may well rise. Our analysis in Section
5 will demonstrate this effect, but as with a dedicated connection the utilisation level upstream will again be
reduced and to this extent it is conceivable that some element of cost offsetting could be incorporated into the
connection charging methodology.
Lower utilisation levels on circuits and equipment will be beneficial in the long-term as it will place less stress on the
network components and consequently result in an extension of the useful life of that equipment, i.e. the asset life.
The operation of embedded generation on the network can significantly reduce the utilisation levels on circuits and
equipment at times of peak load, both local to the generator and on the network upstream. This can prove of real
benefit to the DNO in that it can allow network reinforcement to be delayed or even avoided16. Conversely, where
embedded generation can result in higher network utilisation the effect could be to advance the timing of network
reinforcement. In either case the impact of embedded generation on network reinforcement requirements is very
site specific and depends on a range of factors, such as the loading of the existing network, the projected growth
rate, the location, capacity and characteristics of the embedded generation.
In order to establish the costs and benefits of embedded generation on network utilisation, a simplified computer
based model of each representative network segment has been developed to facilitate the load flow and short
circuit analysis (Section 5). The output from this model demonstrates the effect on network utilisation of different
levels of embedded generation on the network, with the embedded generation connected at various locations, i.e.
at the source substation, at a remote location and at some points in-between.
3.2
System Losses And Overall System Efficiency
3.2.1
Treatment and allocation of losses
Although technical losses on the distribution network17 vary continuously as the load on the network changes it is
usual practice to confine analysis of network technical losses to an assessment of the peak load power loss and the
total annual energy loss18. Indicative loss levels in the Irish electricity system are detailed in Table 3.2 below:
16 It is noted that the DNO is obliged to provide security of supply to users connected to its distribution network and that this security level also needs
to consider the possibility of the loss of output from any embedded generation. Network reinforcement would only be avoided where the DNO
regards the embedded generator as being as secure as its own distribution network.
17 Technical losses are losses associated with the passage of current through the network and the losses that are generated by transformers when
unloaded.
18 To convert the peak power loss to an annual energy loss requires knowledge of the system load duration characteristics, from which the loss load
factor can be derived and applied to the peak power loss to determine the annual energy loss.
-16 -
Table 3-2 Indicative Losses in Irish Electricity System19
Network
Loss
Transmission
4.0%
110 kV stations
0.6%
38kV Network
1.6%
38kV Stations
0.8%
MV Network
2.5%
MV Subs
1.6%
LV Network
3.4%
Total
14.5%
This indicates that a high proportion of the total system losses arise on the distribution networks. Embedding
generation into the distribution networks would tend to reduce the power losses on those networks. The extent of
this reduction would be dependent on the precise location of the generation, the capacity of the generation, the
load in the network and the reduction in circuit utilisation. This would also tend to result in a reduction in
transmission system losses on account of the resulting reduction in power flows on those networks.
Further, the above indicates the significant contribution that micro- and small scale embedded generation could
make in offsetting the system losses, given that ~35% of the overall losses are incurred at the MV transformer and LV
network levels.
Power losses. In the analysis in Section 5 we quantify the change in peak load power loss that results from the
connection of embedded generation on each representative network segment. In particular we determine the
effect on network losses of the connection of embedded generation for a range of generator capacities when
installed at various points on the network. The savings, or otherwise, in system losses are converted into equivalent
monetary values based on information on the current cost of losses.
The connection of embedded generation, assuming it is operational, reduces the demand on the upstream network
at times of peak load whilst leaving the downstream network relatively unaffected and this is seen as a benefit to all
users.
Energy losses. Although running embedded generation at times of peak load will reduce network power losses at
peak load, the reverse may be true at times of light load where operation of embedded generation may actually
increase the losses if exporting power to the grid. Since peak load conditions only exist for a short period during the
day and the period of light load covers a much longer period (i.e. through the night) when electricity demand is low,
the overall effect of running embedded generation throughout any 24-hour period may actually be to increase the
overall energy loss.
With the present commercial arrangements developers of embedded generation are encouraged to optimise their
generation profile against expectations of market price or in response to pricing signals built into the SToD type AER
tariffs20. However, this assumes that the tariffs or market pricing accurately represent the cost of distribution system
losses at different time of day and time of year. If not then it may lead to an increase in the distribution system
19
Marginal Cost of Electricity Service Study; CER 04/240; 1 July 2004
20
Seasonal Time of Day tariffs offer under the Alternative Energy Requirements scheme
-17 -
energy losses, which is in contrast to an energy saving policy, and may require the distribution network operator to
adapt its use of system charges.
3.2.2
System operation costs
Whilst embedded generation will in some applications reduce both peak power losses and annual energy losses and
thereby improve system efficiency, there are other aspects of system operation that will also benefit from the
connection of embedded generation.
The obvious benefit to be gained from the widespread use of wind energy and other indigenous sources of
sustainable energy in the future is that it will reduce the demand for conventional fuel, whether indigenous or
imported, to well below what would be required to keep pace with the current rate of growth in demand with the
present mix of generation plant. This will benefit the country as a whole from a reduction in the cost of imported
fuel and by increasing fuel diversity. Increasing the use of indigenous energy sources will also improve overall
security of supply. Further, reducing the reliance on imported fuels should also reduce the exposure of the Irish
market to the impact of fuel prices spikes and the reduced requirement for conventional fuels will also assist in
extending the projected available life of the indigenous conventional fuel sources.
Another feature of embedded generation is that it can produce reactive power for voltage support that might
normally be met from more remote generators. This can be regarded as an opportunity for the DNO to utilise a
‘point of use’ ancillary service capability of the embedded generation which should reduce the price the DNO has to
pay at the distribution / transmission system interface. The generator can therefore enter the market for supplying
ancillary services and conceivably develop an income from this.
In line with ESBNG ancillary services agreements, it is envisaged that the income would be realised by payments for
producing or consuming reactive power and also being available to produce or consume reactive power. The
present form of agreement to facilitate this service is through a bilateral agreement with ESBNG who, by means of
dispatch instructions, instructs the unit to adjust reactive power output. The Grid Code obliges generators to ensure
that their plant has the physical capabilities to supply ancillary services in each category appropriate to the plant
technology. Generator licences mandate them to offer their ancillary services to the market, under reasonable
terms.
Developing the use of embedded generation to supply ancillary services should benefit the general customer by
increasing the competition for these contracts, with a consequent downward pressure on contract pricing.
Conversely, with embedded generation connected to the distribution network it is anticipated that the DNO will
need to adapt its operations to take a more active role in managing voltage control on the distribution network. This
would be through increased use of automatic control devices and other frequent low-level interventions not
currently incorporated into the present distribution network operation21. This is likely to involve additional
switching operations of the control circuit breakers and associated equipment that will effectively increase the
Operation and Maintenance (O&M) costs. The additional O&M cost is difficult to estimate at this stage.
21
This process of active distribution network management is akin to the practices adopted for the management of the Transmission system.
-18 -
3.3
Security And Quality Of Supply
3.3.1
Security of supply
The various types of embedded generation that can be connected to the distribution network depend, with the
exception of wind energy, on a reliable and steady supply of fuel (or water in the case of hydro stations) to ensure
that embedded generation can operate on a fairly continuous basis.
Wind, on the other hand, is a more intermittent source of energy so that its contribution to the security of the
network is less apparent. A single wind turbine will not generate electricity when the wind speed falls below a
certain level and, although Ireland has the greatest potential for development of wind power in Europe, there are
significant periods when the wind speed is insufficient to operate wind turbines. This implies a ‘firm’ wind
generating capacity of 20% of installed capacity - consistent with recent analysis22 undertaken for wind farms in the
UK advising that the overall ‘firm capacity’ would lie in the range 20-35% of installed capacity. This overall capacity
takes into account aggregation and diversity of the total system wind generation capacity.
The distribution of wind farms and other embedded generation across the network will allow their contribution to
be aggregated. To the extent that wind power can contribute to Ireland’s energy requirements on most days of the
year, and even on those days when there is no wind in some areas, wind and other embedded generation plant in
other areas will generate power that can be injected into the network elsewhere. The contribution from power
available from such aggregated embedded generation resources will impact most on the higher voltage networks,
specifically the transmission system where the effective aggregated power available from embedded generation on
the distribution network makes a positive contribution to the security of the transmission network. This issue is
recognised in the TSO Generator Adequacy Report (GAR) 200423 which indicates a capacity credit of about 200 MW
for 1000 MW of installed wind power allowing for the geographical diversity of the embedded wind generation.
Additionally, it may be argued that the impact of the aggregated contribution from all embedded generation
reduces the ratio of the largest generating unit to total generating system size, hence improving the security of a
system inherently reliant on a few large generation plants.
The presence of embedded generation on the distribution network will, where the generation is available on a
continuous and predictable basis, improve the security of supply to the local area load and supplement the power
available from the grid. For example, in the event of the loss of a 38/10 kV transformer at the primary substation that
supplies local load, secure and reliable embedded generation will be able to continue supplying power to that load.
The extent of this, of course, depends on the magnitude of the generation and the load and the retention of a
suitable link with the main grid or the installation of suitable “island” operation systems.
The availability of secure quantities of embedded generation will therefore be of benefit to the DNO by improving
the security of supply. Where there are significant amounts of reliable embedded generation connected to the
network this can reduce the amount of security-related network investment. However, the benefit is location
dependent and with wind farms likely to be the largest type of renewable generation on the network their overall
contribution to system security will be dependent on an aggregation of their effective output.
22
‘Quantifying the system costs of additional renewables in 2020’, UK DTI, October 2002.
23
Referenced in “Transmission System Operator, Ireland Generation Adequacy Report 2004 – 2010”, page 33
-19 -
3.3.2
Availability and quality of supply
The existing distribution network has only limited amounts of embedded generation connected to it, but with the
Government’s energy targets this is likely to increase substantially over the next few years. It is accepted that,
providing the connection of new generation to the distribution network has been properly designed, the effect will
be to improve both the quality of supply and its availability to the customer. The actual benefit obtained is, like
some other benefits and costs, difficult to quantify and dependent on a number of factors such as the existing
availability and quality of supply, the magnitude of the embedded generation and how it is connected to the
existing network and the existing network configuration.
However, with connection of embedded generation to the network, an obligation is placed on the developer to
ensure that the new generation will perform to the required technical standard when operating in parallel with the
distribution network by complying with specific requirements for protection against over and under voltage, over
and under frequency, and loss of mains. Other requirements that the generator has to comply with include the
frequency of paralleling with the network (to limit the number of step voltage changes as the generation is switched
on and off the network); the maximum limit for the step change in voltage when switching the generation; and
maintaining a satisfactory power factor. The outcome of this is to maintain the quality of supply on the local
electricity distribution network within statutory limits.
These requirements are specified by the DNO following a worst case (maximum generation and minimum load)
system analysis to determine the voltage impact of the new connection and then placing constraints on the voltage
fluctuation at the point of connection which it deems to be appropriate to satisfy its statutory obligations. The DNO
analysis does not consider any measures that the developer may offer to implement that mitigate system voltage
issues on the local network which may negate the need for a direct connection to the network. To the extent that
the new connection provides an improvement in the supply quality24 this may be regarded as a benefit to all users
connected to that local network.
3.3.3
Voltage regulation
The major portion of ESB’s distribution network is characterised by a typical rural network, based on overhead
distribution with long radial MV feeders supplying power to remote loads in sparsely populated areas.
This type of network is therefore very susceptible to poor voltage regulation under peak load conditions25 with
significant voltage drops being experienced between the source substation and the remote end of the MV feeder.
The connection of embedded generation to the network will tend to improve the situation by providing voltage
support, although the extent of any improvement depends largely on where the generation is connected and its
capacity. Depending on the extent and effectiveness of the voltage support provided by the embedded generation
it is possible that the DNO may avoid the need to provide additional means of voltage support.
The operational practices for voltage control in areas where embedded generation are connected will require
agreement between the DNO and the generation developer. Depending on the location of the embedded
generation it may be beneficial for the generator to provide voltage control e.g. in areas where the source
24
This is due to increased fault capacity on the local network following connection of the generation plant and when the plant is operational.
However, this is tempered by the introduction of a voltage transient when the generator connects/disconnects from the local network.
25
It is standard practice for ESB Networks to install a booster transformer at intervals along the trunk of very long medium voltage feeders to control
the voltage profile along the length of the feeder such that limits on voltage regulation are not exceeded.
-20 -
impedance is high hence benefiting from a local source of voltage control. Alternatively, if the generator is operated
in power factor control mode then voltage control will be the responsibility of the DNO. Under these operating
conditions, particularly during light load, there is the possibility that local system voltages could rise above statutory
limits. It would therefore be advantageous under these circumstances to change the generator from power factor
control to voltage control mode. This operational flexibility suggests that it may be beneficial to link the generator
and network control schemes such that optimum control is maintained.
Overall, the DNO and electricity users will benefit from improved voltage regulation, although the extent of
improvement will be site specific. In Section 5 we examine this in some detail for each representative network
segment.
On the cost side, limitations are likely to be imposed on the generator through restrictions on power factor to avoid
further deterioration in the supply voltage. This can be viewed as a cost for the generation developer.
A further consideration with regard to voltage regulation is the requirement imposed on generators that their
sudden connection to or disconnection from the network should not cause an excessive step change in voltage on
the network. Whilst in some cases this may not prove to be a problem, it is possible that the generator will be unable
to be connected at the developer’s preferred location because of a weakness of the distribution system at that point.
In those circumstances it will often be necessary to connect the generator to a stronger part of the network (i.e.
where the short circuit level is higher) and this will involve the developer financing the additional cost of
connection26.
3.3.4
Voltage waveform quality
The technical requirements imposed on embedded generation, as a condition of its connection to the distribution
network, will ensure that the generation will not adversely affect the quality of the supply voltage waveform. In fact,
where the shape of the voltage waveform is less than ideal due to the presence of harmonics on the network, the
embedded generation will generally tend to improve the quality of the waveform by acting as a partial sink for such
distortions.
Limitations imposed on the parallel operation of the embedded generator will minimise the frequency of switching
operations to connect or disconnect the generator from the network, as will limits imposed on the extent of the
allowable step change in voltage. Additionally, the presence of embedded generation will raise the fault level at the
connection point and thereby strengthen the system, so that the magnitude of voltage flicker is reduced. Whilst
reduced voltage flicker is a benefit, the improvement will vary across the network and it is therefore difficult to
quantify this on a generic basis.
Offset against these benefits is the portion of the connection cost that has to be carried by the developer in meeting
voltage waveform quality requirements.
26
This applies equally to all new connections irrespective of whether it is a generation or demand connection.
-21 -
3.4
System Reinforcement Costs
3.4.1
Effect on network fault levels
The strength of the network, or any part thereof, is directly related to its short circuit level. The higher the short
circuit level, the stronger the network becomes, and the more capable it is of accommodating disturbances to the
network such as those caused by the switching of major items of equipment like generators, capacitors and reactors.
Any embedded generation connected to the distribution network will provide a contribution to the system fault
level. In some respects this will strengthen the network and thereby make more capacity available.
In some instances27 where the existing fault level is approaching the ceiling imposed by the switchgear rating, the
connection of generation to the distribution network may be constrained. The result is either that the generation
must be connected elsewhere on the network, which in itself will involve extra cost for the developer28, or that its
connection arrangement is designed specifically to keep fault levels to within rating. This again will involve the
developer in additional costs, though the extent of these will be very site specific.
Similarly, it is possible that the connection of embedded generation may provide a degree of flexibility to the DNO
that can result in the avoidance of reinforcement or replacement of existing plant29. In such cases the “betterment”
needs to be recognised as a benefit attributed to the generation.
3.4.2
Network planning costs and resources
The connection of embedded generation imposes an extra degree of complexity on the system planning process.
Each connection application requires the DNO to examine the impact of the new generation in order to confirm that
the network and other customers connected to it will not be adversely affected.
In addition to the system planning studies that the DNO would normally perform, such as base case load flow,
contingency load flow and short circuit analysis, the DNO has to be satisfied that the step change voltage limits are
not exceeded when the embedded generation is suddenly switched on or off the network. Other technical aspects
that are examined at this stage include harmonics, system losses and network protection.
Each new application for a generator connection that the DNO receives requires it to undertake this process of
evaluation before approval is given for the scheme to proceed. The cost of this additional planning work, i.e. the
connection studies, is passed on by the DNO to the developer of the new generation project.
The cost of the additional system planning requirements is not identified in this study.
3.5
Impact of embedded generation on reinforcement plans
The connection of embedded generation to the distribution network introduces a new source of power on to the
network that in many cases is located much closer to the demand than the existing power source, i.e. the local bulk
supply point. Consequently, when the generation delivering power to the network it will affect the power flow
27
This generally will not apply in rural areas where the fault level on the MV system is relatively low.
28
As discussed in Section 3.3.3 Voltage Regulation.
29
This is likely to require the connection of a number of generators at a single point on the DNO network to provide the necessary continuity in output
to enable avoidance of reinforcement expenditure.
-22 -
between the existing source and the embedded generator. The extent to which the power flow is affected will
depend largely on the magnitude of the connected generation, the configuration of the network and the location of
the generation itself.
In general the effect of the embedded generation will be to reduce power flows on the distribution network when
the generation is in service, although where the generation is teed into the existing network the power flow in the
network in the vicinity of the generator connection may well be increased.
In cases where the change in power flow on the local network is significant, and the output from the generation is
considered a secure and reliable supply30, the embedded generation can have a positive impact as far as the DNO is
concerned in that it may allow the DNO to defer or even avoid altogether the reinforcement of the network in a
particular area.
Similarly, embedded generation on the distribution network will reduce power flow down through the transmission
network to the local area bulk supply point. This can conceivably allow the TSO (i.e. ESB National Grid) to delay
system reinforcement, particularly at the local bulk supply point, providing the generation is of sufficient
magnitude and is available on secure and reliable basis. In the longer term, the overall contribution from a much
higher concentration of embedded generation on the network will be to reduce the power that would be
transported across the transmission system to well below the level resulting from continued use of large
conventional power stations connected to the transmission system. The load-related capital expenditure
requirements of the TSO under this “embedded generation” scenario would also be correspondingly lower.
In order to provide the necessary information to embedded generation developers, there may be a need to provide
transparent and objective rules by which the contribution of embedded generation to system security is calculated
and accounted for within the LCTAS connection design process.
Although the effect of embedded generation on system reinforcement is seen as a real benefit, in that it can allow
network reinforcement to be delayed or avoided altogether, there may be an “up-front” cost to the DNO and the
developer. This is the cost associated with strengthening the local network near to where the generator is
connected, to allow the generation to deliver its contracted power to the network without any constraints.
3.6
System Control, Load Balance And Safety
3.6.1
Control of reactive power flow
The typical rural distribution network in Ireland is characterised by a long radial overhead line with spur feeders
tapped off at various points along the trunk of the feeder between the source and the remote end of the line. Large
voltage drops are an inherent problem with networks of this type and it is the DNO’s practice to strategically locate
boosting transformers at one or more locations en route to keep the voltage profile within the statutory voltage
limits. As voltage drop is directly related to reactive power flow, any action that will minimise the reactive power
flow down the overhead line will reduce the voltage drop down the line. Improved voltage regulation benefits the
consumer through improved quality of supply and benefits the DNO by meeting its obligations with regard to
supply voltage whilst at the same time reducing system losses.
30
This will depend on the generation technology and its output profile. It is unlikely that intermittent generation would be regarded as providing a
“reliable” alternative to the DNO network.
-23 -
The availability of embedded generation can provide the DNO with a localised source of controllable reactive power
that can reduce the reactive power flow through the distribution network. The output from the generator can be
used to reduce the reactive power flow upstream of its connection point and thereby improve system voltage along
the whole feeder length. The extent of the improvement in voltage control is clearly site specific, but the
contribution from embedded generation can be important. This is also recognised by the DNO who have set down
specific requirements for the power factor of the generator output31.
Whilst the control of reactive power flow can bring real benefits to the DNO through an improved voltage profile,
the benefits have an associated cost. To control reactive power32 additional hardware and software is being
developed for large wind farms to meet the requirements of the TSO. It is very likely that the same technology (and
requirements) will soon be applicable for smaller wind farms. However, a more sophisticated control facility will
have an additional cost. It would seem reasonable that where the DNO sees the reactive power availability from
embedded generation as a benefit, the developer should be recompensed for the supply of reactive power.
A further cost to the DNO would arise if the generator absorbed reactive power, in which case reactive power flow
through the transmission system and distribution network would be increased. Although the increase could be
fairly small, it nevertheless would increase the voltage regulation and the losses, and effectively impose a cost on the
TSO and the DNO. For that reason strict control of the power factor is necessary to prevent the embedded generator
operating at leading power factor, i.e. under-excited and thereby absorbing reactive power.
3.6.2
Network constraints and load management
The electricity demand in Dublin is increasing annually at a rate of over 6 percent, whilst in the rest of Ireland the
annual growth rate is between 3 and 4 percent33. Continued growth at these rates will see the demand for electricity
increase by over 60 percent in 10 years. To keep pace with this rate of growth the TSO (National Grid) and DNO (ESB
Networks) will be faced with a significant increase in their load-related capital expenditure budgets.
However, network reinforcement may not be the best option in all cases for various technical and/or economic
reasons, and a more viable solution could be for load to be constrained off the network. This approach has been
adopted on many developed systems around the world and a substantial amount of work on demand-side
management techniques has been pioneered in Northern Ireland by the local electricity utility, Northern Ireland
Electricity.
Whilst there are well-established techniques available for demand management to constrain-off load at peak times,
embedded generation is an ideal tool for the system operator to use to reduce the demand on the distribution
network at peak times. Demand management on other networks in the UK and abroad currently attracts premium
payments from system operators and the provision of a similar facility from embedded generators may also provide
some income to the developer. It will also benefit the TSO and the DNO through a reduction in the amount of
system reinforcement required in their respective load-related capital expenditure budgets.
Continued growth in the number of generators connected to the distribution networks will ultimately have
implications for the operational control of those networks and the control interface with the transmission network.
For example, it may be that clusters of embedded generation could be scheduled to effectively reduce demand such
31
As specified in the Distribution Code
32
Sophisticated hardware and software is being developed to control other parameters, such as peak power output and ramp rate.
33
References from ESB (www.esb.ie) and within the National Allocation Plan (www.epa.ie).
-24 -
that distribution and or transmission system constraints are removed. This is clearly a scenario where the control of
load management would require effective interfacing between the DNO and TSO.
Against the benefits identified above, there would be an the increased cost of communications, both in terms of
equipment and manpower effort. This is necessary to ensure efficient and timely management of the constraints
with the increased number of parties that are involved in the process.
A further cost associated with the operation of network constraints and demand management is the increase in
operation and maintenance (O & M) costs necessary to apply the constraint. Although it is probable that the
embedded generation will operate for long periods between “down-times” the additional control and switching that
is likely to be required to control the generator output to manage demand at peak times is likely to result in
increased O&M costs.
3.6.3
Islanding
In the event of a supply failure to an area of the distribution network in which generation is embedded, protection
equipment can be set to operate (on the basis of the rate of change of frequency) to “island” the embedded
generation and part of the affected network in order to ensure that at least part of the affected load remains
supplied34.
The obvious benefit of this “islanding” capability is that it reduces the amount of lost load. In remote areas that
suffer regular interruptions in supply, the savings in respect of lost load could be relatively high. The economic
savings are dependent on the Value of Lost Load (VoLL) and the outage duration. The DNO will benefit from
reductions in the number of Customer Minutes Lost (CML’s) and Customer Interruptions (CI’s) that are used to
measure supply availability and impact on the allowed DUoS revenue, whilst the customer will benefit from an
improvement in the availability of supply.
To facilitate “islanding” of the network the DNO will be required to pick up the cost of interface protection, such as
that used to detect an excessive rate of change of frequency that will occur in the event of a supply failure. An
additional cost that also has to be borne is for a secure communications channel from the generator to the DNO’s
control centre.
3.6.4
Displaced load
The question of displaced load is closely associated with security of supply and whether embedded generation is
considered as a secure and reliable power source. In cases where the DNO considers the embedded generation this
to be the case, it will allow the generator to contribute to security of supply. In that case the output from the
generator will effectively displace load on the distribution network so that the displaced load can be discounted
from the demand taken from the TSO. This can result in a reduction in the required capacity of the connection assets
between the TSO and the DNO.
34
It is worth noting here that ESB presently forbids islanding due to safety hazard and potential user equipment damage. Provided that these safety
and damage concerns can be addressed through design of the “islanding” system, the costs and benefits can be calculated.
-25 -
Part B – Commercial / Financial Issues
3.7
Commercial Implications
In the context of the connection and operation of embedded generation within an interconnected / meshed
electricity distribution network, other considerations come into play over and above those technical items required
for the embedded generation may be physically connected to the system.
These mainly apply at a commercial level within the cost structure of the proposed embedded generation and the
distribution / transmission system asset owner and operator35. These items are discussed in more detail in the subsections below.
3.7.1
Avoided TUoS Charges
In liberalised / liberalising markets the costs of providing the transmission and distribution systems are controlled
within licence condition constraints and the expenditure is typically capped through an agreed regulatory price
control mechanism. The intention is to prevent abuse of monopoly power and to extract business efficiency from
any over-performance in order to benefit the end customer.
The costs of providing the transmission and distribution systems comprise capital expenditure (asset replacement
etc.) and revenue expenditure (system operation, losses) and are recovered through the Use of System (UoS) charges
levied by the DNO / TSO. These UoS charges recover the costs associated with the provision of the electricity
distribution / transmission system assets and their operation such that the charges at each voltage level and for each
customer type reflect the costs incurred to provide service at that point of supply. Such an approach drives out any
potential for cross-subsidy between customer groups.
The UoS charges provide an incentive to customers to make efficient use of their network connection capacity. This
ensures that the peak demand on the system is limited within the capacity installed in the system to ensure
reliability and security of supply. Peak demand charging is employed both by the DNO within their customer UoS
charges (Maximum Demand charges), and TSO in their entry / exit charges for transmission system connections.
These entry / exit charges are recovered from system generation plant (entry) and DNO and transmission connected
demand (exit). The exact split between the entry and exit charge revenues in recovering the costs of the TSO
depends on the connection charging methodology (shallow or deep) and the allocation of system cost recovery to
generation and demand.
The application of transmission exit charges on the DNOs means that a proportion of the distribution UoS charge
levied on distribution-connected customers is used to recover those transmission exit charges. Therefore, to the
extent that a demand customer commits to reduce their peak demand requirement at times of system peak loading
the DNO receives a direct benefit through a reduction36 in the transmission exit charges payable to the TSO.
35
Dependent on the market status and structure the Asset Owner (AO) may be a separate commercial entity to the System Operator (SO) with
appropriate Asset Use agreements in place between the AO and SO that establish the relationship between these parties and ensure the security and
reliability of the network.
36
The avoided transmission exit charges benefit will include any additional uplift accrued through the associated reduction in the DNO system losses
that come with a reduction in demand. Therefore the kW benefit seen by the DNO at the Transmission system boundary is the demand reduction
uplifted by the applicable site DLAF.
-26 -
This mechanism is equally applicable for embedded generation to the extent that such plant is operating during
times of system peak demand. The local embedded generation output will offset local customer demand giving a
net reduction37 in the DNO peak transmission system exit capacity. Therefore the embedded generation can provide
benefits to the end customer as its operation offsets (fully or partially dependent on the plant reliability) some of the
costs of operating the systems at times of peak demand.
3.7.2
Displaced Load
As with the UoS charges benefit that can be derived from embedded generation operation, the generator may be
regarded as being sufficiently reliable to permanently displace load on the DNO system and contribute to the
security of supply. In this case the displaced load can be discounted from the transmission capacity required by the
DNO. This may allow the DNO to reduce the capacity of the connection assets at the TSO / DNO boundary.
The question of displaced load is closely associated with security of supply and whether embedded generation is
considered as a secure and reliable power source. Examples of embedded generation plant that may be regarded as
being sufficiently reliable to allow permanent load displacement – and the associated accrued benefits to the DNO –
would be Peat, Biomass or gas fired CHP. Other renewable generation technologies such as wind and hydro are
unlikely to provide the necessary reliability.
3.7.3
Capital Cost of Plant
The connection of embedded generation to the distribution network introduces a new source of power on to the
network that in many cases is located much closer to the demand than the existing power source, i.e. the local bulk
supply point. Consequently, when the generation is delivering power to the network it will affect the power flow
between the existing source and the generator, and between the generator and the local customers.
As described in Section 3.5 above, this provides a number of potential benefits. These include allowing the DNO to
defer or avoid reinforcement of the network in a particular area38, and reducing the load-related capital expenditure
required from the TSO
3.7.4
Connection Costs
As described in Section 3.4.2, the connection of embedded generation imposes an extra degree of complexity on the
system planning process. The costs associated with these additional planning activities will be recovered from the
developer by the DNO as part of the overall connection costs.
As described in Section 3.4.1, embedded generation can contribute to system strength by increasing its short circuit
level at the point of connection, and to a lesser degree, further out within the distribution network. Depending on
the identified connection point and its electrical proximity to the transmission system, there may also be some
implications for the transmission system (this is only expected to be the case where a large embedded generator is
proposed). In some respects this can strengthen the network and make more capacity available to enable the DNO
to connect more demand customers.
37
This reduction will also need to account for the losses uplift effect.
38
Deferred of avoided reinforcement capital expenditure will require the embedded generation to have a consistent operating profile. It is unlikely
that ‘intermittent’ generation would be regarded as being a reliable alternative to the DNO network reinforcement.
-27 -
However, where the existing fault level is approaching the ceiling imposed by the switchgear rating, the LCTAS
assessment of the connection application could identify that it is more cost effective to connect the proposed
generator to a point on the distribution network that is physically further away. Such a decision will involve extra
connection cost for the generator, or a modified connection arrangement designed specifically to keep fault levels
to within rating.
3.7.5
System Operation Costs
As described in Section 3.2.2, embedded generation will impact on the costs to the DNO of operating the network.
These may be benefits in the form of reactive power supply and reduced losses, or costs through the need for more
active management.
3.7.6
Wind Power Forecasting
The inherent variability in wind means that with significant levels of embedded wind generation, extra system
operating costs are incurred to maintain the ability to respond to this variation. These extra operating costs may
come from:
•
maintaining other system plant at part output (reduced efficiency, increased fuel costs and lost
opportunity costs) to allow for a rapid ramp-up in the event that the wind stops blowing; or
•
the installation of costly rapid-start plant; or
•
curtailing wind generation.
While variability in output is an inherent property of wind generators, significant efforts have been made in
providing improved forecasting methodologies for wind generation. These can reduce the uncertainty over the
variation in output that will actually occur. Significantly when combined with a short market ‘gate closure’ period,
these forecasting techniques can remove the majority of the output uncertainty. Through increasing the confidence
in the output from wind generation and the communication with the TSO, more effective planning can take place
and any additional system costs may be significantly mitigated.
While any improved forecasting will have an associated cost, it is likely that this will be justified by the reduced costs
in a system with high levels of wind generation.
3.8
Financial Implications
3.8.1
Unit Costs of Generation
Many embedded generation technologies have a unit cost of generation that is driven by their high initial capital
cost, while large fossil fuel plant generation cost is more closely linked to fuel costs. This currently results in higher
unit generation costs for embedded generation. Capital costs for many embedded generation plants are expected
to fall through economies of scale in manufacturing and advances in the emerging technologies on which they may
be based. This reduced capital cost will be directly reflected in the delivered energy unit cost from embedded
generation plant.
Comparison of the unit costs of the embedded generation and the system plant needs to be done carefully, as the
cost of generation is only the cost associated with putting the energy into the system, not the cost to the customer.
-28 -
As a result items related to energy loss benefit, avoided use of system charges, and potentially deferred capital
expenditure need to be accounted for to obtain a complete picture. However, these items are included within the
other cost / benefit items mentioned in earlier Sections and their inclusion here would result in double counting.
3.8.2
Environmental Mitigation Costs
Large fossil fuel power plants are coming under increasingly stringent regulation through measures such as the
Large Combustion Plant Directive (LCPD)39. This may require flue gas desulphurisation, low NOx burners or low
sulphur fuel sources to be utilised, dependent on the generation plant. Each of these items has an associated capital
or revenue cost that will be passed through to the end customers as an increased cost of energy. The impact of the
sulphur emission constraints and forthcoming carbon emissions limits have already seen price movement within the
UK electricity market as system plant operators seek to ensure compliance with emission limits by restricting their
operation.
Embedded generation plants falling below the threshold thermal input criteria will avoid these environmental
mitigation costs, although the level of benefit achieved will depend on the marginal cost of the avoided emission
and the final National Allocation Plan level of carbon emissions allowed for each polluter.
Any benefit that arises will derive from differentials in thermal efficiency of the plant (in terms of total heat use) and
the fuel source (whether it is fossil or renewable). The prices attaching to the respective emissions will need to be
those that are seen in the market for medium to long-term emissions.
3.9
Other Issues
Many embedded generation technologies, such as wind, solar and hydro, use renewable energy sources that are not
“consumed” (i.e. they are constantly replenished whether or not their energy is extracted). Increasing use of
embedded generation can thus reduce the consumption of non-renewable fuels. Generation from biomass sources
essentially replaces one form of fuel with another, but provided that more biomass is grown or produced, it can also
be considered to be “non-consuming”.
A reduction in fuel consumption also implies a reduction in transportation, and the fuel consumed in doing so. Fuelbased embedded generation such as biomass or Energy-from-Waste will require transportation, although this will
typically be local and may occur anyway as part of existing waste disposal systems. The fuel consumption involved
in the local transportation of the fuel to the embedded generation plant will be difficult to quantify for this study and
is regarded as being insignificant in terms of the plant input energy.
3.9.1
Reduction in Emissions
The use of renewable fuels for embedded generation will reduce greenhouse gas emissions. The level of reduction
actually achieved will depend on factors such as:
39
•
the fossil-fuelled generation that is replaced or avoided. For example, the replacement of existing coalfired plant by renewable embedded generation would give a greater emissions reduction than if it is used
to avoid new gas-fired plant.
•
the strategy adopted to manage wind power variability. For example, operating thermal plants at part load
to increase responsiveness will reduce their efficiency, resulting in lower emissions reductions per unit of
wind energy generated.
Directive 2001/80/EC
-29 -
•
the specific mix of embedded generation technologies adopted, remembering that not all embedded
generation is renewable.
The emission reduction calculation will need to take into account the expected operating profile of the embedded
generation (base load, mid merit, peaking / intermittent), its fuel source and thermal efficiency in order to calculate
and value emission savings that reflect actuality. This value is captured within the environmental mitigation costs
assessment.
3.9.2
Avoidance of Carbon Trading Costs
The recently adopted Emissions Trading Directive40 obliges member states of the EU to allocate greenhouse gas
emissions allowances to major emitters, including large thermal power stations.
The total number of allowances must be consistent with each state’s Kyoto commitments, but the allowance
distribution is to be determined by national governments within the National Allocation Plan (NAP)41. A reduction in
generation emissions through an increase in embedded generation could therefore make more allowances available
for other Irish industries. This would reduce the number that would need to be purchased from other member
states, or even provide income from sales of surplus allowances.
This is a macro economic benefit that will accrue as a result of the combined effect of numerous renewable
generation project implementations. As this study is considering a range of discrete embedded generation projects
we have restricted the scope to quantifying the impact of the discrete projects and not provided any study into the
wider, macro economic effect of multiple plants on the Irish economy.
3.9.3
Indigenous Fuel Supply Security
Many embedded generation technologies will not require imported fuels; the wind, water and biomass they rely on
being indigenous. Increased levels of embedded generation can thus contribute to fuel supply security. The actual
increase in security gained will depend on the fuels that embedded generation replaces, and the relative security of
imported oil, coal and gas. However, embedded generation such as gas-fired CHP that relies on imported fuel will
not, of course, contribute to supply security. It may even reduce security if it displaces more secure fuels.
High levels of embedded generation are likely to mean high levels of wind generation. While wind is an indigenous
resource, and is predictable over the longer term, it is variable over the short term, as discussed earlier. It can
therefore be argued that supply security in the short-term (of the order of days or weeks) is actually reduced,
requiring back-up capacity in the form of other fuels.
An obvious benefit from the widespread use of wind energy and other sources of indigenous sustainable energy is
that it offset future demand for conventional fuels, whether they are indigenous or imported. This could even offset
any increase in conventional fuel use to well below what would be required to keep pace with the current rate of
growth in demand with the present mix of generation plant.
This will benefit the country as a whole from a reduction in the cost of imported fuel and by increasing fuel diversity.
40
Directive 2003/87/EC
41
Irish NAP was approved by the European Commission on 7 July 2004.
-30 -
3.9.4
Social Benefit of Green Energy Sales
Renewable energy sources are likely to power a significant part of future embedded generation plants. Such “green”
energy sources can have a number of social benefits, including:
•
Embedded generation using a local fuel supply, principally biomass, can provide income and employment
in growing and handling the fuel, particularly in rural areas. This may represent an alternative or extra
income stream for the agricultural industry;
•
While wind generation provides few permanent local jobs, it can bring income in the form of land rents
and short-term construction work;
•
The strengthening of weak distribution grids by the installation of embedded generation can improve
reliability of supply to local commercial and domestic customers and increase the overall efficiency of local
business through improved quality of supply and / or reduce UoS charges;
•
Reductions in noxious emissions may have positive local health and environmental benefits.
A reduction in fossil fuel use, through expanding embedded generation, does imply a reduction in income in the
fossil fuel supply chain and as such this may have an offsetting effect through reduced employment in the longer
term within the fossil fuel supply sector. The scale of this impact is regarded as being outside the scope of this study
due to its macro economic nature.
3.10
Considerations for Micro- and Small Scale Embedded Generation (SSEG)
The contribution from SSEG units will be effected at the point of use of electricity for LV consumers. This means that
these units will be able to offset the LV system losses to a greater or lesser extent. As identified in Table 3.2 above,
the losses in the MV/LV transformation and LV network amount to some 35% of the overall transmission /
distribution system losses and almost 50% of the typical distribution system loss. Therefore there is significant value
from SSEG both in terms of its potential to avoid load related capital expenditure and to offset energy loss costs.
The connection of significant quantities of SSEG to a particular LV distribution network will present itself on the MV
or HV network in a similar way to a direct connected larger embedded generator and the costs and benefits
discussed in Sections 3.2 through 3.9 will be evident. The discussion below considers some of these items further in
relation to SSEG connections;
Voltage Regulation - The units will provide voltage support to the LV network through the displacement of
demand at the point of use. The voltage profile for the LV Network and the tap setting on the local MV/LV
distribution transformer will determine the extent to which the voltage rise may exceed accepted distribution
network ‘ design’ limits. However, there is the potential to adjust the transformer tap to take into account the
changed voltage profile;
Voltage Unbalance – There is a ‘background’ level of voltage imbalance on LV networks due to the random
connection of users to particular phases along a feeder. This effect is more pronounced the further away from the
distribution transformer. The voltage imbalance at the distribution transformer LV terminals is lower since they are
not affected by the feeder cable voltage drops and this will mitigate the impact of multiple SSEG on voltage
unbalance at the MV and HV levels;
-31 -
Power Flow – Whilst the SSEG penetration remains below the level of demand on an LV network it is unlikely that
there will be issues related to reverse power flow through the distribution transformer. However, should there be
reverse flow (real power or reactive power) through the distribution transformer there may be issues related to the
protection systems and tap changer equipment associated with the transformer, and there could well be cost issues
for the connection of the SSEG beyond this level.
The distribution company may need to consider providing statements on the allowable penetration of SSEG on their
LV networks and certainly should consider a mechanism for treatment of connections that require capital
expenditure on the LV network;
Fault Levels – The introduction of multiple SSEG units onto an LV network will increase the fault level. However,
recent studies41 have shown that the impact is not significant due to the impedance of the LV network. Further, the
contribution to the fault level at higher voltage levels has also been shown to be minimal;
Voltage Step Changes – the SSEG units may be sensitive to the voltage transients that can be seen on LV networks,
say from the disconnection of an adjacent distribution transformer. If this is the case it is likely that the action of
circuit breakers or fuses local to the fault will not cause loss of supply to the unfaulted transformer. However,
protection equipment on the SSEG units may operate and trip the generation and this secondary effect will result in
voltage step change. This may lead to a standard range of protection setting for SSEG plant on a given LV network,
or possibly a generic ‘fault ride through’ capability.
Generation Location – the location of the SSEG units on the LV network will influence the extent of their effect on
the LV network. The location on the MV/HV network of those LV networks with significant SSEG penetration will
have a similar influence on the MV/HV networks as does the location of a larger directly connected embedded
generator;
The detailed calculation of the costs and benefits of SSEG is included within an Addendum to this report.
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4.
Representative Network Identification and Modelling
4.1
Electricity distribution in Ireland
4.1.1
General
The population of Ireland is concentrated in the cities of Dublin, Cork, Limerick and Galway, in towns along the east
coastal strip and the south east corner, and inland within commuting distance Dublin, the main urban development.
The remainder of the population is distributed across the country in small county towns, villages, on farms and on
individual plots of land. About two-thirds of Ireland’s population is concentrated in probably less than one-quarter
of its surface area.
ESB Networks has over the years developed its distribution network to supply electricity to customers across the
length and breadth of the country, such that 38 kV high voltage primary substations are located in every county42,
with 20 kV or 10 kV medium voltage networks distributed from these substations or from 110 kV substations on the
transmission system of ESB National Grid. Consequently the bulk of ESB’s distribution network is located in rural
areas and is likely to remain so for the foreseeable future, even with continued growth of the Irish economy and the
resulting expansion of the area of urban and semi-urban development, particularly in areas within reasonable
commuting distance (i.e. 100 km) of Dublin.
The rural distribution network is characterised by long, single circuit overhead lines, configured as a radial network at
either 10 kV or 20 kV, to supply an area of low load density, with densities typically in the range 20 kW/km2 to
50 kW/km2. These medium voltage networks are either supplied from the 38 kV high voltage distribution system at
38/10 kV and 38/20 kV primary substations or directly from the 110 kV transmission system via 110/20 kV
substations.
At the other extreme, in central Dublin, electricity distribution is via 38 kV and 10 kV underground cable networks
that supply customers in high load density areas, with densities typically in the range 5,000 kW/km2 to
10,000 kW/km2. The transmission system injects power into Dublin at various locations at 110 kV43. From these grid
substations a 38 kV high voltage cable network is distributed across the city, with 38/10 kV primary substations
located at various points on route. The 38 kV network in central Dublin is interconnected to an extent, with closed
ring circuits between bulk supply points linking a number of primary substations on route. A 10 kV cable network
interconnects primary substations, but this network is operated as a radial network with open points at strategic
points along its length. The cable lengths are relatively short with 38 kV and 10 kV substations located much closer
together than in the rural areas. The 10 kV cable network supplies 10 kV/LV secondary distribution substations
across the city from which domestic customers and the bulk of ESB’s commercial and light industrial customers
receive their supply. The 10 kV distribution network also provides supplies directly at 10 kV to some large customers.
In the larger towns and on the outskirts of Dublin and the other cities where there is a mix of domestic, commercial
and light industrial load the load density is typically in the range 1,000 kW/km2 to 4,000 kW/km2 and the network is a
combination of underground cable and overhead line with circuits generally of a more moderate length.
42
The ESB Networks distribution system includes 110kV system voltages within the Dublin area distribution network.
43
At a number of number of grid substations power is injected initially at 220 kV, but stepped down immediately to 110 kV, and then supplied to the
38 kV distribution network from the 110 kV grid substations through 110/38 kV transformers.
-33 -
ESB has been implementing a voltage conversion programme for some time now in which new developments are,
where appropriate, being supplied at 20 kV, instead of 10 kV. ESB is also converting parts of its 10 kV network to
20 kV, as circuits and equipment are upgraded or replaced under ESB’s programme of asset replacement. Therefore,
depending on the location, the medium voltage network in these areas can be either a 10 kV network or a 20 kV
network supplied from either the 38 kV high voltage distribution network or the 110 kV transmission system. To
enable network conversion to continue in the future it is ESB practice to install dual voltage transformers (i.e.
38/20/10 kV with two secondary windings) at many primary substations, particularly in rural areas.
4.1.2
Rural networks
The bulk of rural distribution networks are similar in construction and in basic design configuration. The high
voltage (38 kV) and medium voltage (10 and 20 kV) distribution networks in rural areas are characterised by radial
networks that supply power to sparsely distributed loads over long, single circuit overhead lines. Consequently
under extreme conditions many rural networks are regularly subject to problems with voltage quality and
availability of supply.
In an analysis of the range of representative network types the obvious feature that distinguishes one network type
from another is the combination of voltage levels used to deliver power from the transmission system to the
customer. In common with other distribution companies the vast majority of ESB Networks’ customers receive their
electricity supply at low voltage, i.e. 400/230 V, and as such the low voltage distribution system is common to all
voltage combinations.
The most common combinations of distribution voltage levels in use in rural areas of Ireland are:
a)
38/10 kV distribution
b)
38/20 kV distribution.
c)
However, there are also a number of cases where the 110 kV transmission system has been used directly to
feed the distribution system and this has produced a third representative rural network type:
d)
110/20 kV distribution.
The principal characteristics of each of the three rural network types are summarised below.
38/10 kV networks. The 38 kV network receives its supply from the 38 kV bus bars of the local 110/38 kV
transmission substation of ESB National Grid. In the rural areas the 110/38 kV substation capacity is generally based
on one or two 31.5 MVA transformers.
From the bulk supply point typically two outgoing feeders supply power for up to four other 38/10 kV primary
substations. The network is configured radially and open points isolate the 38 kV network from its neighbour, which
is sourced from another transmission substation. The 38 kV circuits that connect the 38/10 kV primary substations
are all single circuit overhead lines in the rural areas.
At the primary substations, the most common arrangement is for two 38/10 kV, 5 MVA transformers to supply the
10 kV switchboard, although there are examples of single transformer primaries, with 2 MVA and 5 MVA transformer
capacities the most commonplace. Examination of a sample of rural networks has shown that typically between
three and five 10 kV radial feeders are supplied from the primary substation and the 10 kV feeder is configured such
-34 -
that from the main “trunk” of the feeder are routed a number of lengthy “spur” circuits to supply loads located some
distance from the main route taken by the trunk. Also it is usual for a number of much shorter “stub” circuits to be
teed off the trunk to supply customers that are located just off the main route. The trunk of the network is generally
a 3-phase circuit. However, the spur circuits can be either 3-phase or single-phase depending on the size of the load
and the length of the spur. ESB Networks use standard conductor sizes for the 38 kV and 10 kV overhead lines. In
cases where the primary substation is located in a town the outgoing feeder may be run underground, over the
initial part of the route, and for these relatively small lengths ESB Networks again use standard cable sizes.
The longer circuits also incorporate voltage-regulating transformers (i.e. “boosters”) at strategic points along the
main trunk of the feeder, and in some exceptional cases booster transformers are connected in the spur, to boost the
voltage downstream.
From the sample of networks analysed in our study it would seem that current practice for the connection of wind
farms and small hydro sets (typically less than 4 MW) to the 10 kV network is through a single dedicated circuit to the
10 kV bus bars of the nearest 38/10 kV primary substation, bypassing any existing 10 kV network infrastructure that
may be in the vicinity. This type of connection for the embedded generation will have little effect on the 10 kV
distribution system, though it will effect the performance of the 38 kV network upstream.
Figure 4.1 shows a typical 38/10 kV rural network including a connection arrangement commonly used by
developers to connect an embedded generator to the distribution system at the local primary substation.
38/20 kV networks. In a similar way to that used to supply the 38/10 kV distribution network, the typical 38/20 kV
rural network is supplied from the 110/38 kV grid substation via one or two 110/38 kV, 31.5 MVA transformers. In
many rural areas, the 20 kV network runs alongside the 10 kV network, as part of the voltage conversion programme,
and consequently it is common practice for the 20 kV network to take its supply from the same 38 kV primary
substation as a neighbouring 10 kV network. In those instances, at least in the sample we examined, one 38/10 kV,
5 MVA transformer supplied the local 10 kV network and one 38/20 kV, 5 MVA transformer supplied the local 20 kV
network. In time as voltage conversion continues the logical process would be for the 10 kV network to be
upgraded to 20 kV. The key aspect is that the same 38 kV network is often used to supply the 10 kV and / or the
20 kV network, i.e. it is typically common to both.
Analysis of a small sample of 20 kV circuits showed that typically two 20 kV outgoing feeders distributed power from
the 20 kV bus bars of the 38/20 kV primary substation. The 20 kV feeders are in the main, like the 10 kV rural feeders,
single circuit overhead lines configured as radial networks to sparsely distributed loads. The advantage of 20 kV
distribution over 10 kV distribution is that the same power can be distributed much further at 20 kV, nominally by up
to four times, so that the supply area of a 20 kV network should extend well beyond that of the 10 kV network.
Alternatively, the 20 kV network can cover a similar supply area, but handle a much greater load, effectively
providing capacity to handle significant projections in load growth. As with 10 kV feeders, a number of lengthy spur
circuits and shorter stub circuits are teed off the trunk of the 20 kV feeder. The trunk of the network is again
essentially a 3-phase circuit, with the spurs either 3-phase or single-phase depending on the size of the load and the
length of the spur. ESB Networks use standard conductor sizes for the 20 kV overhead lines and cables.
The current practice for the connection of wind farms and small hydro sets to the 20 kV network (typically less than
10 MW) is, like that at 10 kV, through a single dedicated circuit to the 20 kV bus bars of the nearest 38/20 kV primary
substation, bypassing any existing 20 kV network infrastructure that may be in the vicinity. This type of connection
for the embedded generation will have little effect on the 20 kV distribution system, though it will effect the
performance of the 38 kV network upstream.
-35 -
Figure 4.2 shows a typical 38/20 kV rural network with connection arrangement.
110/20 kV. The number of networks with direct transformation from transmission voltage to medium voltage is
fairly limited. In most cases it has been the practice to step down from 110 kV to 38 kV for onward distribution to
other 38 kV primary substations, which would increase the potential supply area from the 110 kV transmission
substation compared with 20 kV distribution. However, in exceptional cases, such as the Arigna network in Leitrim,
where there was an existing 110 kV grid substation in place (following the closure of the local power station) and no
38 kV network within 25 km there was an economic case for direct transformation from 110 kV to 20 kV.
The installed capacity at the 110/20 kV grid substations will be higher than that installed on the 38/20 kV or 38/10 kV
primary substations, but for Arigna, the case in our sample, the 110/20 kV substation provides supplies through a
single 15 MVA transformer.
The 20 kV outgoing feeders are similar in design to those employed in the 38/20 kV network, although given the
potential for increased installed capacity at the 110/20 kV substation the number of outgoing 20 kV feeders could be
higher than for a typical 38/20 kV network.
Figure 4.3 shows a typical 110/20 kV rural network.
4.1.3
Semi-urban networks
On the outskirts of the major cities and towns the electricity demand comes basically from a mix of domestic,
commercial and light industrial customers. The outskirts are essentially semi-urban areas with power injected into
the area from 110 kV transmission substations. At the main bulk supply points it is standard practice to operate with
two, or possibly three 110/38 kV, 63 MVA transformers in service to supply the 38 kV network. From the bulk supply
points, typically three or more 38 kV feeders connect with other 38/10 kV primary substations through a
combination of radial and closed loop circuits. In the sample network provided for semi-urban areas, up to four
primary substations were connected, with open points segregating it from an adjacent network. The 38/10 kV
primary substations on the outskirts of Dublin are based, typically, on two 10 MVA transformers with up to five
outgoing 10 kV feeders routed from each primary substation, supplying power to 10 kV/LV secondary distribution
substations on route. The load density in semi-urban areas is much higher than in rural areas, so that circuit lengths
are generally much shorter. The 10 kV feeders run between primary substations, with open points located
strategically along the route, and in a typical network there are no spur circuits tapped off to supply distant loads
and only a few short stubs to customers just off the main route.
The 38 kV and 10 kV circuits are predominantly run underground, although there may be examples, depending on
the specific location, where a combination of overhead lines and underground cables carry power to the primary
substations.
Figure 4.4 shows a typical semi-urban 38/10 kV network on the outskirts of Dublin. At the present time ESB Networks
voltage conversion programme is understandably focused on the rural areas as a means of improving system
voltage, reducing losses and improving overall network efficiency. There is some 20 kV network near each of the
main cities, but as yet this does not extend much to semi-urban areas and for the purpose of this study the semiurban network is considered exclusively as a 38/10 kV network.
Embedded generation in semi-urban areas can take a number of forms with wind energy, CHP, landfill gas and
biomass a particular possibility. Brownfield sites are the likeliest location for new embedded generation in semiurban areas and these could conceivably be connected directly to the main 38/10 kV primary substations at either
-36 -
voltage, depending on the magnitude of the generation, or else teed into the 10 kV network at some point near to
where the generation is situated.
4.1.4
Dense urban networks
In central Dublin there is a prime example of how embedded generation is located and operates on the distribution
network. A large processing company has its own generating facilities on its factory site, for economic and security
of supply reasons, and a contract to both export to and import power from the grid depending on its operating
circumstances.
The electrical system on the site is connected by a 10 kV cable circuit that is routed in and out of the site between
two 38/10 kV primary substations (i.e. A and B) . These substations are themselves connected into two separate
38 kV circuits run over different supply routes between two 110/38 kV grid substations (i.e. X and Y). The cable
circuit between the A and B substations is dedicated entirely to the connection of the factory supply to the 10 kV
network. Under normal operation the 10 kV feeder between A and B substations is open at either A or B, so that the
supply to the factory site is connected to either A or B substations, but not both simultaneously.
Figure 4.5 shows the supply arrangement for connection of the embedded generation to the 38/10 kV network in
central Dublin. The rest of the supply arrangement shown in Figure 6.5 is reasonably representative of the supply
arrangement in a dense urban area in the larger cities.
The 38 kV network interconnects a number of 38/10 kV primary substations either in a closed ring from a single bulk
supply point, or in one or more 38 kV circuits laid over different routes between the two bulk supply points. Typically
each 38/10 kV primary substation on the 38 kV network has an installed capacity of one or two 10 MVA transformers,
although there are cases where 15 MVA transformers have been used. In order to limit short circuit levels, it is
standard practice to configure the network so that for each group of primaries, a maximum of two 110/38 kV
transformers (whether located at the same bulk supply point or at different ones) is used to supply the demand.
Typically from the main bulk supply points several 10 kV feeders are routed to other primaries and bulk supply
points across the city. A significant level of interconnection exists, but strategically placed open points ensure the
10 kV network is operated as a radial network.
4.1.5
Identification of representative network types
The review of rural, semi-urban and dense urban networks in Ireland, has identified five principal network types that
are considered further in this section in a more quantitative manner. The five representative network types are:
44
•
Type 1 - 38/10 kV rural,
•
Type 2 – 38/20 kV rural,
•
Type 3 – 110/20 kV rural44,
•
Type 4 – 38/10 kV semi-urban,
•
Type 5 – 38/10 kV dense urban.
The analysis presented in this report has been limited to determining the effects of embedded generation specifically on the distribution network.
Consequently power system studies of the 110/20 kV network type have not been undertaken. Although, the principles for system modelling and
power system studies presented in this report can be similarly adopted to examine the effects of embedded generation with respect to the 110 kV
system, the model of the transmission system would have to take account of load and generation despatch.
-37 -
At an early stage in the study PB Power held discussions with ESB Networks to identify a reasonable sample of
distribution networks that could be analysed to determine their principal characteristics with a view to placing each
network in one of the above categories. From this representative sample it was intended to define the principal
physical attributes of each network with a view to producing representative system models for each network type
that can be used in power system studies to determine the impact on system performance of embedded generation.
4.2
Topographical analysis
In undertaking topographical analysis of a sample of distribution networks it is recognised that the size of the
sample has unavoidably been limited, because of the extent of work involved in analysing the networks in the first
instance and the limited timescale and budget available to cover all aspects of the Scope of Work. Nevertheless we
have sampled, either in whole or in part, a minimum of fifteen high voltage networks, and sixty medium voltage
circuits. The sampled networks were taken from areas where there is a reasonable expectation of future
development of embedded generation based on sustainable energy resources.
The purpose of undertaking topographical analysis of the sampled networks was basically to determine the principal
physical characteristics of each of the five representative network types defined in Section 4.1.5 above.
4.2.1
Principal network characteristics
There are a number of distinctive features of any distribution circuit, or group of circuits that form a network45 and
which can be used to characterise it for analytical purposes. These are:
•
Primary substation and feeder voltages
•
Type of network (i.e. overhead or underground)
•
Installed primary substation and distribution transformer capacity
•
Load supplied (or load density)
•
Area of supply
•
Feeder physical characteristics (i.e. numbers and lengths of trunk, spurs and stub circuits)46
•
Voltage control facilities.
In order to characterise the network types by their physical parameters, raw data provided by ESB Networks for each
circuit in the sample was analysed to establish data for each of the above characteristics. The raw data consisted of
single line diagrams of the 38 kV network, geographic layouts of the medium voltage distribution network,
substation and feeder loads, transformers, overhead line and cable data.
45
In our discussions with ESB Networks at which a number of sample networks were provided, it was understood that they use the term “network” to
refer to a grouping of up to four primary substations, i.e. from one to four primaries.
46
ESB Networks, in common with other utilities, use standard conductor sizes for their overhead line and underground cable networks. Consequently
there is a degree of commonality with regard to conductor types and sizes across the various network types.
-38 -
4.2.2
Rural networks
The sample of rural networks analysed topographically covered areas in which there was considered to be significant
potential for the connection of generation based on sustainable energy type resources. The sample networks
analysed were located in the counties of Donegal, Leitrim, Kerry and Kildare47. The analysis included one of the
Midlands networks to determine whether there is a significant difference between rural networks in the west of
Ireland, where the networks are acknowledged as “weak” and networks in the Midlands where some reinforcement
to the higher voltage networks had been made in the past to accommodate local power stations that have only
recently been retired. Subsequent analysis showed that whilst the Midlands network was more heavily loaded than
most of the rural networks in the sample, the difference was not significant and therefore the Midlands network was
included as part of the rural network sample.
In the assessment of the rural networks we have considered first the analysis of the medium voltage networks.
The analysis of medium voltage feeder circuits routed from a single primary substation showed a significant
difference in the lengths of individual feeders. This reflects on the amount of installed transformer capacity and the
connected load and can also affect the requirements for voltage control. Consequently in our topographical analysis
we have specifically determined the characteristics of the shortest feeder, an average length feeder and the longest
feeder48 so that the three are represented in our system model used to analyse the effects of embedded generation
on the network.
10 kV feeder circuits. Table 4.1 summarises the principal characteristics of the 10 kV rural networks. It is evident
from the table that there is a significant difference between the shortest and longest feeder lengths and the
respective loads on these feeders. There is also a corresponding difference in the total load on each feeder, although
the average distribution transformer utilisation is fairly comparable (i.e. between 36 and 42 percent). The difference
in circuit length and circuit loads will significantly impact on the voltage, utilisation and losses associated with the
respective feeder. This is demonstrated later in section 5, in which the results of power system studies are presented,
but there is evidence of this in the fact that the longest feeder has typically two voltage boosters installed along its
trunk.
The data presented in Table 4.1 is used directly in the development of the system model of the representative rural
38/10 kV network. The topographical analysis of the 10 kV feeders is presented fully in Appendix D.
47
The number of networks in our sample was necessarily limited. There are obviously other counties and areas of rural Ireland that have similar
potential for sustainable energy type developments that could equally have been included in the sample.
48
The data presented in Table 6.1 for the shortest, average length and longest feeder was derived from a review of the medium voltage feeders
supplied from seven 38/10 kV primary substations, for which the shortest and longest feeders were identified and an average taken. The average
length feeder was derived from the full sample.
-39 -
Table 4.1: Principal physical and load characteristics of medium voltage feeders on 10 kV rural
networks
Shortest feeder
Average feeder
Longest feeder
3357
4853
6733
Average transformer utilisation (%)
36
38
42
Feeder trunk length (km)
5.6
11.2
18.5
1
2
3
2.4
3.0
3.7
3
6
10
Average stub length (km)
0.3
0.3
0.4
Total circuit length (km)
9.0
19.2
33.1
0
0
2
Load connected to trunk (kW)
432
664
1014
Load connected to spur circuits (kW)
417
640
984
Load connected to stub circuits (kW)
297
456
700
1146
1760
2698
Installed transformer capacity (kVA)
Number of spur circuits
Average spur length (km)
Number of stub circuits (km)
Number of booster transformers
Total connected load (kW)
20 kV feeder circuits. A similar treatment was applied to a smaller sample of 20 kV networks and the results of this
analysis are presented in Table 4.2.
From the table it is evident that whilst there is still a significant difference in the length and the total load associated
with the shortest and longest feeders, the differential is not as large as with the 10 kV feeder circuits and this is
reflected to some extent in the fact that the longest feeder in this case does not require booster transformers to
support the voltage.
It is also of note that although the 20 kV feeders in the sample were longer than the 10 kV feeders in Table 4.1 the
20 kV feeder loads were lower and the average distribution transformer utilisation was roughly half that of the
transformers connected to the 10 kV feeder. The 20 kV feeders sampled were located in North Donegal and Leitrim
and it is possible that 20 kV feeders in other areas could be more heavily loaded. However, the principal objective of
the analysis is to demonstrate where the costs and benefits lie and in that respect we consider the data obtained
adequate for the purpose of this study.
The data presented in Table 4.2 is used directly in the development of the system model of the representative rural
38/20 kV network. The topographical analysis of the 20 kV feeders is presented fully in Appendix B.
-40 -
Table 4.2: Principal physical and load characteristics of medium voltage feeders on 20 kV rural
networks
Shortest feeder
Average feeder
Longest feeder
5415
6202
10393
21
27
16
12.0
16.8
18.4
2
3
4
1.8
3.0
6.0
6
7
7
Average stub length (km)
0.5
0.6
0.6
Total circuit length (km)
18.6
30.2
46.9
0
0
0
Load connected to trunk (kW)
560
820
935
Load connected to spur circuits (kW)
310
453
516
Load connected to stub circuits (kW)
216
315
357
1086
1588
1808
Installed transformer capacity (kVA)
Average transformer utilisation (%)
Feeder trunk length (km)
Number of spur circuits
Average spur length (km)
Number of stub circuits (km)
Number of booster transformers
Total connected load (kW)
38 kV networks. The analysis of rural high voltage networks was based on a sample of four, supplying a total of
seventeen 38/10 kV and 38/20 kV primary substations. The 38 kV networks that supply the primary substations
generally are configured as radial circuits from a single source 110/38 kV grid station to outlying primary substations,
from which the medium voltage network is distributed. Alternatively, the supply from the source 110/38 kV grid
station can be connected as a closed ring circuit connecting up to two primary substations on route. For the
purpose of the analysis presented in section 7 of this report we have modelled the 38 kV network as a radial
connection to two outlying primary substations.
Table 4.3: Principal physical characteristics of 38 kV high voltage networks
Installed grid station 110/38 kV transformer capacity
1 (or 2) x 31.5 MVA
Number of 38 kV primaries supplied from grid station
2 to 4
Number of outgoing 38 kV feeders from grid station
2 to 3
Average length of 38 kV feeders between primaries
10 km
Table 4.3 summarises the principal characteristics of the 38 kV network and Figure 4.4 shows a typical 38 kV network
in the rural areas.
4.2.3
Semi-urban networks
The analysis of semi-urban networks was based on data for an area outside central Dublin. A typical high voltage
distribution network that supplies semi-urban areas on the outskirts of Ireland’s largest cities was described in subsection 4.1.3 and is not repeated here. However, although the 38 kV network configuration may be similar to that
shown in Figure 4.4 for a typical rural network, there are some significant differences. In particular the semi-urban
-41 -
networks are predominantly underground cable networks, the grid station capacities are higher (typically 2 x
63 MVA) transformers and the primary substations are closer together.
The results of topographical analysis of a sample of twenty-four 10 kV feeder circuits from four primary substations
that supply the semi-urban areas are presented in Table 4.4. Again we have identified the characteristics for the
shortest, average length and longest feeders.
Table 4.4: Principal physical and load characteristics of medium voltage feeders on 10 kV semiurban networks
Shortest feeder
Average feeder
Longest feeder
2038
4726
6926
Average transformer utilisation (%)
62
37
30
Feeder trunk length (km)
1.7
3.0
4.6
Number of spur circuits
-
-
-
Average spur length (km)
-
-
-
Number of stub circuits (km)
-
1
2
Average stub length (km)
-
1.0
1.1
Total circuit length (km)
1.7
4.0
6.7
-
-
-
1192
1232
1441
Load connected to spur circuits (kW)
-
-
-
Load connected to stub circuits (kW)
-
448
522
1192
1680
1963
Installed transformer capacity (kVA)
Number of booster transformers
Load connected to trunk (kW)
Total connected load (kW)
The data presented in Table 4.4 is used directly in the development of the system model of the representative semiurban 38/10 kV network. The topographical analysis of the 10 kV feeders is presented fully in Appendix B.
4.2.4
Dense urban networks
The analysis of dense urban networks was based on data for a part of 10 kV distribution network in Central Dublin
supplied from Inchicore and Francis Street 110/38 kV grid stations. The high voltage network in this area was
described previously in sub-section 4.1.4 and is therefore not described here.
The results of topographical analysis of a sample of nine 10 kV feeder circuits from two primary substations that
supply this dense urban area are presented in Table 4.5. Again we have identified the characteristics for the shortest,
average length and longest feeders.
-42 -
Table 4.5: Principal physical and load characteristics of medium voltage feeders on 10 kV dense
urban networks
Shortest feeder
Average feeder
Longest feeder
3260
6288
6425
Average transformer utilisation (%)
36
22
55
Feeder trunk length (km)
1.2
1.7
2.2
Number of spur circuits
-
-
-
Average spur length (km)
-
-
-
Number of stub circuits (km)
-
-
1
Average stub length (km)
-
-
0.1
Total circuit length (km)
1.2
1.7
2.3
-
-
-
1110
1290
3204
Load connected to spur circuits (kW)
-
-
-
Load connected to stub circuits (kW)
-
-
157
1110
1290
3361
Installed transformer capacity (kVA)
Number of booster transformers
Load connected to trunk (kW)
Total connected load (kW)
It is acknowledged that the sample size is small and as a result the load on the longest feeder, in particular, may be
unrepresentatively high, as denoted by the 55% average transformer utilisation. We will comment further on this in
Section 5, if it is seen to significantly effect the results of the analysis on this type of network.
The data presented in Table 4.5 is used directly in the development of the system model of the representative dense
urban 38/10 kV network. The topographical analysis of the 10 kV feeders is presented fully in Appendix B.
4.3
Power system modelling
The summarised results of the topographical analysis presented in Tables 4.1 to 4.5 for each network type have been
used as the basis of the power system models used in our analysis of the effects of embedded generation on the
performance of the distribution networks.
Steady state models of each network type have been developed using PSS/E power system analysis software that is
used extensively by system planners in ESB and in major utilities in Britain and elsewhere.
In undertaking the analysis we have developed a number of models that are summarised briefly below:
a)
Rural 110/38/10 kV network
A detailed study of the 110/38/10 kV rural network was undertaken based on the results of the topographical
analysis described in sub-section 4.2. The results of the study are presented in Section 5 as an example for illustrative
purposes of the analysis involved in assessing the costs and benefits of embedded generation.
The model represented the 110/38/10 kV grid station with two 31.5 MVA transformers installed supplying the local
38/10 kV primary substation with two 38/10 kV, 5 MVA transformers and two remote 38/10 kV primary substations of
similar installed capacity located 5 km and 10 km respectively from the grid station. The remote primary substations
-43 -
are each supplied radially via a single 38 kV feeder circuit from the grid station. Figure 4.6 shows the system model
used in studies of the 110/38/10 kV network.
Three outgoing radial 10 kV feeders representing typically the shortest, average length and longest feeder supply
the load from each primary substation. The load on each circuit was consistent with that determined in the analysis
presented in sub-section 4.2.2, representing ESB Network’s estimate of current peak demand.
Load flow and short circuit analysis was undertaken on the model for the base case (i.e. no embedded generation),
and for increasing levels of embedded generation (up to 5 MW) connected to each 10 kV feeder in turn at the most
remote primary substation, directly to the 10 kV bus bars at this primary substation and at various points on the
38 kV network. The location and amount of embedded generation was varied to identify the impact this had on the
system power flows, circuit utilisation, voltages, losses and short circuit levels.
The same model was then modified to take account of a 4 percent annual growth rate projected over a 5-year and
10-year period to investigate the costs and benefits over a longer term.
b)
Rural 38/20 kV network
The full model used in the study of the 110/38/10 kV network demonstrated the effect of the placement of
embedded generation on the 38 kV network. The location of embedded generation on the 38 kV network has only a
second order effect on the performance of the medium voltage (i.e. 10 kV or 20 kV) network and similar results for
the 110/38/20 kV network can be expected for the 110/38/20 kV network, for those cases where generation is
connected on the 38 kV network.
Consequently a reduced model was used to study the impact of embedded generation on the 20 kV network. The
model represented the 38/20 kV primary substation with two 10 MVA installed supplying three outgoing 20 kV
feeders representing the shortest, average length and longest feeder circuits as identified in the topographical
analysis and each loaded as defined in sub-section 4.2.2.
The analysis undertaken with this model has studied the effect on the system power flows, circuit utilisation,
voltages, losses and short circuit levels of increasing levels of embedded generation (up to 5 MW) connected to each
20 kV feeder in turn and directly to the 20 kV bus bars at the primary substation.
c)
Semi-urban 38/10 kV network
The model used to represent this network type is of similar configuration to that used to study the 38/20 kV rural
network, with only the primary substation, the outgoing medium voltage feeders, load and embedded generation
modelled.
In the urban areas because the medium voltage network is heavily interconnected (although essentially operated as
a radial system) the 38/10 kV primary substations typically are based on a single 38/10 kV, 10 MVA transformer. The
model reflects this and again three outgoing 10 kV feeders, representing the shortest, average length and longest
feeders with their respective loads, according to the analysis described in sub-section 4.2.3, have been represented.
-44 -
d)
Dense urban 38/10 kV network
A similar model to that developed for the semi-urban 38/10 kV network was used to study the effect of embedded
generation on dense urban networks, but with feeder data based on the analysis presented in sub-section 4.2.4.
Details of the models used in the analysis including figures showing the respective network configuration can be
found in Appendix C.
-45 -
-46 -
-47 -
-48 -
-49 -
-50 -
-51 -
5.
Power System Studies
5.1
Purpose of studies
Power system studies were undertaken as the first stage in the process to determine the level of costs and benefits
associated with embedded generation on the distribution system.
The studies have concentrated on determining the impact the embedded generation has upon the steady state
operation of the distribution system49. In particular, load flow and short circuit analysis has examined the effect
increasing levels of embedded generation the high voltage and medium voltage networks will have on the
following:
a)
Circuit and equipment loading
b)
Technical losses
c)
Voltage and voltage control requirements
d)
Short circuit levels.
Load flow studies have determined the effect of embedded generation on circuit loading in order to identify when
connection of embedded generation influences the requirements for reinforcement of the network compared with
base case conditions, i.e. no embedded generation, either by increasing the utilisation of the circuit to the point
where it needs to be reinforced, or conversely by its presence avoiding, or at least delaying, the need for
reinforcement.
Load flow studies also identify the effect the generation has upon system technical losses. Depending on whether
they increase or reduce as a result of the connection of the generator, these will be either viewed as a definite cost or
a benefit to the DNO.
Similarly load flow studies determine the voltage at each node on the system model and as such are used to
determine the effect the generation will have on the system voltage profile. In this way we can compare the
voltages with generation present on the system against base case conditions, i.e. no embedded generation, to
determine if the generation can reduce the need for voltage control devices, such as booster transformers and
power factor correction capacitors.
Finally short circuit analysis has determined the effect the connection of embedded generation to the network will
have on system fault level. In examining the fault level the critical issue here is whether existing fault levels are close
to the installed switchgear rating, and whether the connection of the generator will increase the fault level to or
above the switchgear rating. If that were to be the case then it would have a major impact on the economic viability
of the embedded generation since it would require changes to the system design, constraints on system operation,
or upgrade of switchgear; all of which would increase the connection cost for the embedded generation Developer.
49
There are other concerns associated with the dynamic performance of the generator and the network that are not addressed here. The study of the
dynamic performance would require specific modelling of frequency and voltage control devices of generation and is therefore considered at this
time a site-specific issue.
-52 -
In this section we present the results of the power system studies and identify the specific impact of the embedded
generation in comparison with the base case for each of the four representative network types. In Section 6 the
results of the studies are then processed using the methodology to convert the technical costs and benefits into
actual monetary values, so that a comparative analysis can be made to put each cost and benefit into perspective.
The results of the power system studies are presented in more detail in Appendix C
5.2
Effect of embedded generation on network performance
Load flow and short circuit analysis of each representative network type was undertaken using the models
established in Section 4. In determining the effect of embedded generation on network performance we have
compared the performance with embedded generation connected against a base case condition with no embedded
generation. The studies have determined network conditions with increasing levels of generation embedded in the
network at the high voltage and medium voltage levels from 1000 kW to 5,000 kW.
The effect of the generator on network performance was also examined with respect to its location and our analysis
presents the results of studies with the generator located at various points on the network. The locations considered
for the connection of the generator were at:
a)
The source 110/38 kV substation and connected directly to the 38 kV bus bars at that substation,
b)
5 km from the source 110/38 kV substation and connected via a dedicated feeder to the 38 kV bus
bars at that substation,
c)
Connected to a tee-point midway along the 10 km 38 kV feeder from the source grid station to the
remote 38/10 kV or 38/20 kV primary substation,
d)
At the remote primary substation and connected directly to the 38 kV bus bars at that substation,
e)
At the remote primary substation and connected directly to the 10 kV or 20 kV bus bars at that
substation,
f)
5 km from the remote primary substation and connected via a dedicated feeder to the 10 kV or 20 kV
bus bars at that substation,
g)
Connected directly to the trunk of the outgoing feeder circuit at its mid-point,
h)
Connected directly at the end of a remote spur off the trunk of the outgoing feeder from the remote
primary substation,
i)
Connected directly to the remote end of the trunk of the outgoing feeder circuit.
With regard to locations g) to i) above, we have determined the effect of connecting the generation to the three
feeder lengths identified in Section 4, i.e. shortest, average and longest length feeders.
-53 -
5.3
Effect of embedded generation on low density 110/38/10 kV rural
networks
In order to satisfy one of the conditions of the Terms of Reference, that requires the report to provide a detailed
example of the analysis that has been undertaken to establish the level of costs and benefits associated with
embedded generation, we present a detailed description of the results associated with the rural 110/38/10 kV
network. A less detailed presentation of the results is provided for the other representative networks in the main
text of the report, but the complete study results are available in Appendix C.
5.3.1
Analysis of 110/38/10 kV rural networks
Load flow studies have been undertaken on the basis that strict control of system voltage is observed. The results of
the analysis are presented fully in Appendix C of the report, which summarises the assumptions made for voltage
control.
The results presented in this section of the report concentrate on the effect of the generation on the following
parameters in comparison with the base case study with no embedded generation present:
a)
Real and reactive power import at the grid and primary substations
b)
Real and reactive power losses at the grid and primary substations
c)
Voltage profile along the medium voltage feeders
d)
Circuit utilisation.
It is these figures that are used in Section 6 to determine the actual costs and benefits associated with the
generation.
Table 5.1 shows the effect of increasing amounts of embedded generation on the real and reactive power imported
by the network on the HV side of the 110/38 kV transformers at the source substation with the generation at
different locations on the 38 kV and 10 kV networks in comparison with the base case. Table 5.2 converts the power
import values in Table 5.1 into the respective reductions (or savings) in imported power that result from the
connection of embedded generation. A sample of these results, illustrating the reductions in imported power due to
embedded generation, for study cases 2, 3, 4L, 5L, 6L, 8 and 10 are presented graphically in Figures 5.1 and 5.2
respectively. The Figures show that with cases 2, 8and 10 (i.e. where the generator is connected at 38 kV or directly
on to the 10 kV bus at the remote 38/10 kV primary) the connection of 5 MW of generation effectively reduces the
imported power at the 110 kV bus by the same amount. Cases 4L, 5L and 6L, in which the generator is connected at
some point along the outgoing 10 kV feeder from the remote substation, show a much poorer return when the
generator output is greater than about 3 to 3.5 MW, although below that figure these cases provide a better return
than the rest with case 4L, for example, providing a reduction in imported power of over 3 MW when the generator is
delivering 2.5 MW. The significant factor in this respect is the magnitude of the system technical losses.
Transformers can be obviated. Connection of the generator the end of the trunk or a remote Tables 5.3 and 5.4
show the respective real and reactive power losses on the system as affected by the magnitude and location of the
embedded generation, for a range of generator output up to 5 MW. Tables 5.5 and 5.6 respectively show the
corresponding savings (or increases) in system losses. Figures 5.3 and 5.4 present in graphic form the loss savings for
the same study cases as in Figures 5.1 and 5.2.
-54 -
Figure 5.3 shows that there are significant loss savings to be made by connecting the generation at some point on
the outgoing 10 kV feeder providing the capacity does not exceed between 2 to 3 MW, with the most benefits being
achieved by connecting the generator near to mid-point along its trunk. Above 3 to 3.5 MW the advantage is lost
and the embedded generation starts to increase the system losses.
Figure 5.4 shows the effect of embedded generation on reactive power losses. In most of the cases presented the
generation produces savings in reactive power losses for generation up to 5 MW. However, when the generator is
connected at or near the end of the outgoing feeder the reactive power loss increases when the generator output
exceeds 3 MW.
Table 5.7 summarises the effect of increasing amounts of embedded generation on the network voltage. In the Base
Case (study case 1) with no embedded generation the voltage profile along the average length and longest 10 kV
feeders falls below 0.95 per unit with the standard DNO practice of operating with two booster transformers
installed strategically along the longest feeder to give maximum voltage boost. In study cases 2 and 3 with the
generator either connected directly to the 10 kV bus at the remote primary or via a dedicated feeder to the same bus
the connection provides no voltage relief. In cases 4, 5 and 6 with the generator connected to the outgoing feeder
there can be a significant improvement in the voltage profile. With the generator connected midway along the
trunk of the feeder the under voltage condition is avoided and with a generator of 2.5 MW or above the need for
booster spur will also control system voltage within the required +/-5% limit, but with a 5MW generator voltage
constraints apply to prohibit the connection of this size of generator at the end of the longest feeders. In cases 7 to
10 with the generation connected at 38 kV and upstream of the remote primary it provides little or no relief to the
voltage problems on the outgoing 10 kV feeders from the remote primary. The full voltage profile is presented in
Appendix C.
Table 5.8 summarises the effect of increasing amounts of embedded generation on circuit loadings (i.e. utilisation).
In the Base Case (study case 1 - with no embedded generation) all circuits in the model were operating within their
nominal rating and therefore not overloaded. With embedded generation connected at 38 kV (cases 7 to 10) or
directly (case 2) and indirectly (case 3) to the 10 kV bus at the remote primary, the network is again operating within
rating. The connection of a 2.5 MW generator or a lower rated machine to the 10 kV feeders will not overload the
feeders, but a 5 MW set would produce overloads particularly on the shortest and average length feeders and a
marginal overload on the longest feeder. However, as stated voltage constraints prohibit the connection of such a
relatively large generator to the end of the 10 kV feeders. The circuit utilisation is listed in detail in Appendix C.
-55 -
Figure 5.1: Reduction in imported real power as affected by embedded generation
6000
Reduction in imported power at 110kV (kW)
5000
Case 2 - Direct conn to remote 10kV pry
Case 3 - Dedicated feeder 5km from remote 10kV
pry
4000
Case 4L - Conn mid-trunk on longest 10kV feeder"
Case 5L - Conn to remote end of spur on longest
10kV feeder
3000
Case 6L - Conn to trunk end on longest 10kV
feeder
Case 8 - Dedicated 38kV feeder 5km from source
pry
2000
Case 10 - Direct conn to 38kV bus at remote pry
1000
0
0
1
2
3
4
5
Embedded Generator output (MW)
-56 -
6
Figure 5.2: Reduction in imported reactive power as affected by embedded generation
3000
Reduction in imported reactive power at 110kV (kW)
2000
1000
Case 2 - Direct conn to remote 10kV pry
Case 3 - Dedicated feeder 5km from remote 10kV pry
0
0
1
2
3
4
5
6
Case 4L - Conn mid-trunk on longest 10kV feeder
Case 5L - Conn to remote end of spur on longest 10kV
feeder
-1000
Case 6L - Conn to trunk end on longest 10kV feeder
Case 8 - Dedicated 38kV feeder 5km from source pry
-2000
Direct conn to 38kV bus at remote pry
-3000
-4000
-5000
Embedded generator output (MW)
-57 -
Table 5.1: Real and Reactive Power Import at 110kV bus as a function of Embedded Generation
MW gen
Real power import (kW)
0
18300
18300
18300
18300
18300
18300
18300
18300
18300
18300
18300
18300
18300
18300
18300
1
17268
17276
17226
17170
16886
17228
17168
16820
17234
17158
16816
17296
17298
17292
17264
2.5
15714
15790
15748
15698
15240
15920
16034
15738
15950
16042
15572
15792
15816
15738
15728
5
13168
13496
13658
13908
13822
14116
14814
16432
14232
14846
15944
13286
13342
13238
13178
Case 2
Case 3
Case 4S
Case 4A
Case 4L
Case 5S
Case 5A
Case 5L
Case 6S
Case 6A
Case 6L
Case 7
Case 8
Case 9
Case 10
MW gen
Reactive power import (kVAr)
0
8340
8340
8340
8340
8340
8340
8340
8340
8340
8340
8340
8340
8340
8340
8340
1
7818
7846
7790
7746
7484
7794
7746
7414
7790
7748
7410
7942
7942
7906
7910
2.5
7088
8262
8264
8362
6638
9400
9484
8652
9422
9486
8366
7356
7386
7308
7284
5
6030
9970
10676
10848
10596
10990
11494
12572
11082
11514
12300
6394
6444
6344
6282
Case 2
Case 3
Case 4S
Case 4A
Case 4L
Case 5S
Case 5A
Case 5L
Case 6S
Case 6A
Case 6L
Case 7
Case 8
Case 9
Case 10
-58 -
Table 5.2: Savings in Real and Reactive Power Import at 110kV bus as a function of Embedded Generation
MW gen
Real power import savings (kW)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1032
1024
1074
1130
1414
1072
1132
1480
1066
1142
1484
1004
1002
1008
1036
2.5
2586
2510
2552
2602
3060
2380
2266
2562
2350
2258
2728
2508
2484
2562
2572
5
5132
4804
4642
4392
4478
4184
3486
1868
4068
3454
2356
5014
4958
5062
5122
Case 2
Case 3
Case 4S
Case 4A
Case 4L
Case 5S
Case 5A
Case 5L
Case 6S
Case 6A
Case 6L
Case 7
Case 8
Case 9
Case 10
MW gen
Reactive power import savings (kVAr)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
522
494
550
594
856
546
594
926
550
592
930
398
398
434
430
2.5
1252
78
76
-22
1702
-1060
-1144
-312
-1082
-1146
-26
984
954
1032
1056
5
2310
-1630
-2336
-2508
-2256
-2650
-3154
-4232
-2742
-3174
-3960
1946
1896
1996
2058
Case 2
Case 3
Case 4S
Case 4A
Case 4L
Case 5S
Case 5A
Case 5L
Case 6S
Case 6A
Case 6L
Case 7
Case 8
Case 9
Case 10
-59 -
Figure 5.3: Real power loss savings from embedded generation
1000
500
0
Real power loss savings (kW)
0
1
2
3
4
5
-500
6
Case 2 - Direct conn to remote 10kV pry
Case 3 - Dedicated feeder 5km from remote 10kV
pry
Case 4L - Conn mid-trunk on longest 10kV feeder
-1000
Case 5L - Conn to remote end of spur on longest
10kV feeder
Case 6L- Conn to trunk end on longest 10kV
feeder
-1500
Case 8 - Dedicated 38kV feeder 5km from source
pry
-2000
Case 10 - Direct conn to 38kV bus at remote pry
-2500
-3000
-3500
Embedded Generator output (MW)
-60 -
Figure 5.4: Reactive power loss savings from embedded generation
1500
1000
500
Reactive power loss savings (kVAr)
Case 2 - Direct conn to remote 10kV pry
Case 3 - Dedicated feeder 5km from remote 10kV pry
0
0
1
2
3
4
5
6
Case 4L - Conn mid-trunk on longest 10kV feeder
Case 5L - Conn to remote end of spur on longest 10kV
feeder
-500
Case 6L - Conn to trunk end on longest 10kV feeder
Case 8 - Dedicated 38kV feeder 5km from source pry
-1000
Case 10 - Direct conn to 38kV bus at remote pry
-1500
-2000
-2500
Embedded generator output (MW)
-61 -
Table 5.3: Real power losses as affected by embedded generation
MW gen
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
0
17
221
716
954
17
221
716
954
17
221
716
954
17
221
716
954
17
221
716
954
1
15
180
711
906
15
181
728
924
15
179
685
879
15
177
619
811
14
167
356
537
2.5
12
136
719
867
13
151
780
944
13
150
739
902
13
150
694
857
11
121
257
389
5
9
95
722
826
12
155
989
1156
12
175
1126
1313
13
182
1368
1563
13
174
1294
1481
110kV
38kV
10kV
110kV
38kV
10kV
110kV
38kV
10kV
110kV
38kV
10kV
110kV
38kV
10kV
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
MW gen
0
Total
Total
Total
Total
Study 2
Study 3
Study 4S
Study 4A
Study 4L
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
17
221
716
954
17
221
716
954
17
221
716
954
17
221
716
954
17
221
716
Total
954
1
15
179
686
880
15
175
619
809
14
164
297
475
15
179
686
880
15
179
634
828
2.5
14
176
915
1105
14
179
994
1187
13
156
724
893
14
175
885
1074
14
179
1002
1195
5
13
192
1687
1892
15
213
2224
2452
17
279
3781
4077
13
188
1556
1757
15
214
2254
2483
110kV
38kV
10kV
110kV
38kV
10kV
110kV
38kV
10kV
110kV
38kV
10kV
110kV
38kV
10kV
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
MW gen
Total
Total
Total
Total
Study 5S
Study 5A
Study 5L
Study 6S
Study 6A
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
Total
0
17
221
716
954
17
221
716
954
17
221
716
954
17
221
716
954
17
221
716
954
1
14
164
293
471
15
221
714
950
15
222
714
951
15
203
709
927
15
187
722
924
2.5
13
148
571
732
13
220
710
943
13
230
729
972
12
184
714
910
12
148
722
882
5
17
258
3324
3599
9
219
706
934
9
254
710
973
9
165
718
892
9
112
713
834
110kV
38kV
10kV
110kV
38kV
10kV
110kV
38kV
10kV
110kV
38kV
10kV
110kV
38kV
10kV
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
Study 6L
Total
Total
Study 7
Study 8
-62 -
Total
Study 9
Total
Study 10
Total
Table 5.4: Reactive power losses as affected by embedded generation
MW gen
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
0
631
1049
499
2179
631
1049
499
2179
631
1049
499
2179
631
1049
499
2179
631
1049
499
2179
1
560
922
497
1979
562
925
519
2006
558
918
482
1958
554
911
445
1910
539
879
240
1658
2.5
470
778
502
1750
495
828
600
1923
493
825
513
1831
493
827
488
1808
431
732
145
1308
5
331
653
504
1488
439
837
935
2211
469
895
732
2096
485
915
868
2268
473
891
733
2097
110kV
38kV
10kV
110kV
38kV
10kV
110kV
38kV
10kV
110kV
38kV
10kV
110kV
38kV
10kV
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
MW gen
Total
Total
Total
Total
Total
Study 2
Study 3
Study 4S
Study 4A
Study 4L
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
0
631
1049
499
2179
631
1049
499
2179
631
1049
499
2179
631
1049
499
2179
631
1049
499
2179
1
558
919
483
1960
553
910
445
1908
527
870
185
1582
558
918
482
1958
553
915
454
1922
2.5
535
905
612
2052
541
915
658
2114
503
844
410
1757
533
901
595
2029
542
912
662
2116
5
508
947
1049
2504
548
1008
1353
2909
659
1209
2378
4246
499
934
974
2407
551
1012
1370
2933
110kV
38kV
10kV
Total
110kV
38kV
10kV
Total
110kV
38kV
10kV
Total
110kV
38kV
10kV
Total
110kV
38kV
10kV
Total
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
MW gen
loss
loss
Study 5S
Study 5A
Study 5L
Study 6S
Study 6A
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
0
631
1049
499
2179
631
1049
499
2179
631
1049
499
2179
631
1049
499
2179
631
1049
499
2179
1
527
870
182
1579
565
1048
498
2111
565
1049
498
2112
564
1025
495
2084
563
1014
504
2081
2.5
487
820
323
1630
474
1045
496
2015
475
1062
509
2046
470
1006
497
1973
469
971
504
1944
5
625
1151
2080
3856
339
1042
493
1874
342
1079
496
1917
336
987
501
1824
333
932
498
1763
110kV
38kV
10kV
Total
110kV
38kV
10kV
Total
110kV
38kV
10kV
Total
110kV
38kV
10kV
Total
110kV
38kV
10kV
Total
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
Study 6L
Study 7
Study 8
-63 -
Study 9
Study 10
Table 5.5: Savings in real power losses as affected by embedded generation
MW gen
0
Real power loss (kW)
0
0
0
Real power loss (kW)
0
0
0
Real power loss (kW)
0
0
0
0
0
Real power loss (kW)
0
0
0
Real power loss (kW)
0
0
0
0
0
0
1
2
41
5
48
2
40
-12
30
2
42
31
75
2
44
97
143
3
54
360
417
2.5
5
85
-3
87
4
70
-64
10
4
71
-23
52
4
71
22
97
6
100
459
565
5
8
126
-6
128
5
66
-273
-202
5
46
-410
-359
4
39
-652
-609
4
47
-578
-527
110kV
38kV
10kV
Total
110kV
38kV
10kV
Total
110kV
38kV
10kV
Total
110kV
38kV
10kV
Total
110kV
38kV
10kV
Total
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
MW gen
Study 2
Study 3
Study 4S
Study 4A
Study 4L
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
2
42
30
74
2
46
97
145
3
57
419
479
2
42
30
74
2
42
82
126
2.5
3
45
-199
-151
3
42
-278
-233
4
65
-8
61
3
46
-169
-120
3
42
-286
-241
5
4
29
-971
-938
2
8
-1508 -1498
0
-58
-3065
-3123
4
33
-840
-803
2
7
-1538 -1529
110kV
38kV
10kV
Total
110kV
38kV
10kV
110kV
38kV
10kV
Total
110kV
38kV
10kV
Total
110kV
38kV
10kV
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
MW gen
Total
Total
Study 5S
Study 5A
Study 5L
Study 6S
Study 6A
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
3
57
423
483
2
0
2
4
2
-1
2
3
2
18
7
27
2
34
-6
30
2.5
4
73
145
222
4
1
6
11
4
-9
-13
-18
5
37
2
44
5
73
-6
72
5
0
-37
-2608
-2645
8
2
10
20
8
-33
6
-19
8
56
-2
62
8
109
3
120
110kV
38kV
10kV
Total
110kV
38kV
10kV
Total
110kV
38kV
10kV
Total
110kV
38kV
10kV
Total
110kV
38kV
10kV
Total
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
Study 6L
Study 7
Study 8
-64 -
Study 9
Study 10
Table 5.6: Savings in reactive power losses as affected by embedded generation
MW gen
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
71
127
2
200
69
124
-20
173
73
131
17
221
77
138
54
269
92
170
259
521
2.5
161
271
-3
429
136
221
-101
256
138
224
-14
348
138
222
11
371
200
317
354
871
396
-5
691
212
-436
-32
-233
83
-89
82
5
300
110kV
loss
MW gen
38kV 10kV
loss
loss
192
110kV
Total
loss
38kV 10kV
loss
loss
Total
162
154
110kV
38kV
loss
loss
10kV loss
Total
146
134
-369
110kV
38kV
10kV
loss
loss
loss
Total
158
158
-234
110kV
38kV
10kV
loss
loss
loss
Total
Study 2
Study 3
Study 4S
Study 4A
Study 4L
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
73
130
16
219
78
139
54
271
104
179
314
597
73
131
17
221
78
134
45
257
2.5
96
144
-113
127
90
134
-159
65
128
205
89
422
98
148
-96
150
89
137
-163
63
102
-550
-325
41
-854
-730
-1879
-2067
-228
-754
5
123
110kV
loss
MW gen
38kV 10kV
loss
loss
83
110kV
Total
loss
38kV 10kV
loss
loss
Total
-28
-160
110kV
38kV
loss
loss
10kV loss
Total
132
115
-475
110kV
38kV
10kV
loss
loss
loss
Total
80
37
-871
110kV
38kV
10kV
loss
loss
loss
Total
Study 5S
Study 5A
Study 5L
Study 6S
Study 6A
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
104
179
317
600
66
1
1
68
66
0
1
67
67
24
4
95
68
35
-5
98
2.5
144
229
176
549
157
4
3
164
156
-13
-10
133
161
43
2
206
162
78
-5
235
-102
-1581
-1677
7
6
305
3
262
355
416
5
6
110kV
loss
38kV 10kV
loss
loss
Study 6L
292
110kV
Total
loss
38kV 10kV
loss
loss
Study 7
Total
289
-30
110kV
38kV
loss
loss
10kV loss
Study 8
-65 -
Total
295
62
-2
110kV
38kV
10kV
loss
loss
loss
Study 9
Total
298
117
1
110kV
38kV
10kV
loss
loss
loss
Study 10
Total
Table 5.7: Summary of embedded generation effects on 110/38/10 kV rural network voltage
Study
EG location
Comment on voltage effects
1
Base case (No EG)
Under-voltages on average & longest 10 kV feeders
2
EG connected direct to 10 kV bus at
Under-voltages on average & longest 10 kV feeders
Case No.
remote primary
3
EG 5 km from remote with direct
Under-voltages on average & longest 10 kV feeders
connection to 10 kV bus
4
EG connected mid-trunk on
Voltage controlled within limits (i.e. +/- 5% of nominal) with
outgoing 10 kV feeders
generation > 1 MW to 5 MW. At 2.5 MW and above no longer a
requirement for booster transformers.
5
EG connected at end of spur on
Voltage controlled within limits with generation of 2.5 MW or
outgoing 10 kV feeder
less. Voltage constraints prohibit connection of 5MW generator
at this location.
6
EG connected at end of trunk on
Voltage controlled within limits with generation of 2.5 MW or
outgoing 10 kV feeder
less. With the 1 MW generator only one booster is required and
with the 2.5 MW generator there is no requirement for booster
transformers. Voltage constraints prohibit connection of 5MW
generator at this location.
7
EG direct connection to source
Under-voltages on average & longest 10 kV feeders
38 kV bus
8
EG 5 km from source with direct
Under-voltages on average & longest 10 kV feeders
connection to 38 kV bus
9
EG connected midway along 38 kV
Under-voltages on average & longest 10 kV feeders
feeder between source substation
& remote primary
10
EG connected direct to 38 kV bus at
Under-voltages on average & longest 10 kV feeders
remote primary
-66 -
Table 5.8: Summary of embedded generation effects on 110/38/10 kV rural network circuit
loadings (i.e. utilisation).
Study
EG location
Comment on equipment utilisation
1
Base case (No EG)
No overloads
2
EG connected direct to 10 kV bus at
No overloads
Case No.
remote primary
3
EG 5 km from source with direct
No overloads
connection to 38 kV bus
4
EG connected mid-trunk on
Connection of a 5 MW generator produces significant overloads
outgoing 10 kV feeders
on the shortest and average length feeders and a marginal
overload on the longest feeder. The smaller generators do not
produce overloads.
5
EG connected at end of spur on
Connection of a 5 MW generator produces significant overloads
outgoing 10 kV feeder
on the shortest and average length feeders and a marginal
overload on the longest feeder. The smaller generators do not
produce overloads. However, voltage constraints prohibit
connection of 5MW generator at this location in any case.
6
EG connected at end of trunk on
Connection of a 5 MW generator produces significant overloads
outgoing 10 kV feeder
on the shortest and average length feeders and a marginal
overload on the longest feeder. The smaller generators do not
produce overloads. However, voltage constraints prohibit
connection of 5MW generator at this location in any case.
7
EG direct connection to source
No overloads
38 kV bus
8
EG 5 km from source with direct
No overloads
connection to 38 kV bus
9
EG connected midway along 38 kV
No overloads
feeder between source substation
& remote primary
10
EG connected direct to 38 kV bus at
No overloads
remote primary
-67 -
Table 5.9 summarises the effect of increasing amounts of embedded generation on short circuit levels. The
contributions were based on those from a maximum generator size of 5MW. The table shows that in rural areas the
increase in fault level due to generation is relatively small, with the contribution from the generators to fault level at
110 kV, 38 kV and 10 kV estimated at 0.1 kA, 0.4 kA and 1.7 kA respectively. The additional fault current does not
therefore raise the fault level above the typical rating of switchgear installed at these voltages, although there are
some 12 kA rated re-closers in services against which an estimated maximum fault level of 10.6 kA is possible with
the contribution from embedded generation taken into account.
Table 5.10 summarises in graphic form the results of the analysis of the 110/38/10 kV network, where those cases
yielding benefits can be identified at a glance.
-68 -
Table 5.9: Summary of effect of embedded generation on short circuit levels in rural area
Type of switchgear
Voltage (kV)
Switchgear
Maximum fault Maximum generator Maximum fault level with
rating (kA)
level (kA)
fault contribution (A)
gen connected (kA)
Comment
Main bus circuit breaker
110
20
10.0
127
10.1
Within rating
Main bus circuit breaker
38
20
10.1
387
10.5
Within rating
Main bus circuit breaker
20
16
6.2
845
7.0
Within rating
Re-closer
20
12.5
6.2
845
7.0
Within rating
Expulsion fuse
20
12
6.2
845
7.0
Within rating
Load break switch
20
16
6.2
845
7.0
Within rating
Main bus circuit breaker
10
16
8.9
1747
10.6
Within rating
Re-closer
10
12
8.9
1747
10.6
Within rating, but approaching marginal
Expulsion fuse
10
16
8.9
1747
10.6
Within rating
Load break switch
10
16
8.9
1747
10.6
Within rating
Note: The fault contribution is based on that from a 5 MW generator.
-69 -
Table 5.10: Summary of costs and benefits from embedded generation on rural 10kV networks
a) Cases that produce a reduction in imported power
0
1
2.5
5
1
2
3
4S
4A
4L
5S
5A
5L
6S
6A
6L
7
8
9
10 Gen
(MW)
Study cases
Colour Key:
produces reductions in real and reactive imported power
produces increase in imported reactive power
b) Cases that produce a reduction in power losses
0
1
2.5
5
1
2
3
4S
4A
4L
5S
Study cases
Colour Key:
produces savings in real and reactive power losses
increases real power losses
increases real and reactive power losses
-70 -
5A
5L
6S
6A
6L
7
8
9
10 Gen
(MW)
c) Cases that produce under voltages and over voltages
0
A, L
1
A, L
A, L
A, L
A, L
A, L
A, L
S
A
2
3
4S
4A
4L
S
A
S
A
5S
5A
A, L
A, L
A, L
A, L
1
A, L
A, L
A, L
A, L
2.5
5
S
A
L
S
A
L
A, L
A, L
A, L
A, L
5L
6S
6A
6L
7
8
9
10
Gen
(MW)
Study cases
Colour Key:
produces voltages within +/- 5% of nominal
produces under voltage along feeder (designated by an S, A or L)
produces over voltage along feeder (designated by an S, A or L)
d) Cases that produce overloads
0
1
2.5
5
1
2
3
4S
4A
4L
Study cases
Colour Key:
avoids overloads
produces overloads
-71 -
5S
5A
5L
6S
6A
6L
7
8
9
10
Gen
(MW)
e) Cases that produce fault levels in excess of switchgear rating
With the present rural area fault levels and the level of embedded generation, switchgear ratings should not be at risk due to connection of new generation.
-72 -
5.3.2
Effect on costs and benefits accrued over 10 year period
In sub-section 5.3.1 we have examined in detail the technical performance of the representative rural network with
embedded generation connected, whilst supplying the current levels of peak demand. In rural areas the growth in
demand in forecast to average between 3 and 4 percent per annum over the next few years. In this sub-section we
examine the impact on system performance of a sustained annual growth rate of 5 percent over a 10-year period
through load flow studies for year ‘5’ and year ‘10’, having already presented the results of year ‘0’ in sub-section
5.3.1.
To illustrate the effects of load growth on the costs and benefits associated with embedded generation, we have
confined our analysis to a single generator size, i.e. 2.5 MW. Voltage constraints identified with the 5 MW generator
in the previous sub-section encouraged us to study a mid-range generator size to avoid the possibility of further
constraints being encountered which could limit the determination of costs and benefits.
Table 5.11 shows the effect of embedded generation on imported real and reactive power at through the 110 kV bus
at the source 110/38 kV source primary at years 0, 5 and 10. In Table 5.11 for cases 4, 5 and 6 only the results for
generation connected to the longest feeder are presented. Figures 5.5 and 5.6 show the results graphically in terms
of the reduction in imported power in comparison with the base case (i.e. no embedded generation). It is evident
from Figure 5.5 that when the generation is connected to the 10 kV feeders, there is a significant reduction in
imported real power over the period. This can be attributed to the fact that as load grows along the feeder, the
power delivered by the 2.5 MW generator that at full output would have been a major source of power loss, is offset
and the overall effect is to significantly reduce the real power losses. This is evident later in Figure 5.7.
Table 5.12 shows the effect of embedded generation on real and reactive power losses respectively and Figures 5.7
and 5.8 show the corresponding savings in real and reactive power losses compared with the base case (i.e. no
embedded generation) in years 0, 5 and 10 over the period.
The load flow studies detailed in Appendix C show a major deterioration in voltage conditions along the 10 kV
feeders by year 5 in all cases except those to which generation is connected (i.e. cases 4, 5 and 6). It is evident from
the studies that significant voltage support will be required on these feeders before year 5 and the studies show that
this can be provided by embedded generation providing it is reliable and available to cope with higher load
conditions. The benefits from embedded generation can in this case be equated to the savings in the cost of
providing voltage support or a re-configuration of the network to transfer load to other circuits.
Similarly the studies show that embedded generation connected to the outgoing 10 kV feeders will avoid an
overload on the longest 10 kV feeder by year 5 and marginal overloading on the shortest and average length feeders
by year 10. The benefits from embedded generation can in this case be equated to the savings in the cost of system
reinforcement.
-73 -
Figure 5.5: Reductions in imported real power as affected by embedded generation over 10 year period
6000
Reduction in imported power at 110kV (kW)
5000
4000
Case 2 - Direct conn to remote 10kV pry
Case 3 - Dedicated feeder 5km from remote 10kV pry
Case 4L - Conn mid-trunk on longest 10kV feeder
Case 5L - Conn to remote end of spur on longest 10kV feeder
3000
Case 6L - Conn to trunk end of longest 10kV feeder
Case 8 - Dedicated 38kV feeder 5km from source pry
Case 10 - Direct conn to 38kV bus at remote pry
2000
1000
0
0
2
4
6
8
10
Year
-74 -
12
Figure 5.6: Reductions in imported reactive power as affected by embedded generation over 10 year period
4500
Reductions in imported reactive power at 110kV (kVAr)
4000
3500
Case 2 - Direct conn to remote 10kV pry
3000
Case 3 - Dedicated feeder 5km from remote 10kV pry
2500
Case 4L - Conn mid-trunk on longest 10kV feeder
2000
Case 5L - Conn to remote end of spur on longest 10kV
feeder
Case 6L - Conn to trunk end of longest 10kV feeder
1500
Case 8 - Dedicated 38kV feeder 5km from source pry
1000
Case 10 - Direct conn to 38kV bus at remote pry
500
0
0
2
4
6
8
10
-500
-1000
Year
-75 -
12
Table 5.11: Effect of Embedded Generator Location on Real and Reactive Power Import on HV Side of 110/38 KV Transformer at Grid Substation Supplying
Rural 10 KV Network over 10 Year Period
Embedded generator output = 2.5 MW in all cases
Annual growth rate = 4%
Rural 110/38/10 kV network
Power flow on HV side of 110/38 kV transformer as a function of Embedded Generator location in years 0, 5 and 10
Year
0
5
10
0
5
10
0
5
10
0
5
10
0
5
10
Generator node
-
-
-
200
200
200
299
299
299
266
266
266
272A
272A
272A
Power import (kW)
18298
22780
29174
15714
20130
26466
15790
20240
26568
15240
19212
24216
15738
19514
24924
Reactive Power import (kVAr)
8340
11032
15722
7088
9648
13938
8262
10912
15288
6638
8776
11650
8652
10134
14230
Study 1 - Base case
Study 2 - Direct
Study 3 - Dedicated gen.
Study 4 - Generator
Study 5 - Gen. connected
connection of gen to
feeder 5km from remote
connected mid-trunk
to remote end of mid-
remote 10kV Pry
10kV Pry
-76 -
point spur
Rural 110/38/10 kV network
Power flow on HV side of 110/38 kV transformer as a function of Embedded Generator location in years 0, 5 and 10
Year
0
5
10
0
5
10
0
5
10
0
5
10
0
5
10
Generator node
273
273
273
3100
3100
3100
3101
3101
3101
3102
3102
3102
100
100
100
Power import (kW)
15572
19370
24788
15792
20270
26644
15816
20278
26674
15738
20208
26568
15728
20174
26476
Reactive Power import (kVAr)
8366
9840
14108
7356
10004
14564
7386
10020
14588
7308
9946
14438
7284
9904
13948
Study 6 - Gen. connected at Study 7 - Direct connection Study 8 - Gen connected via
remote end of trunk
of generator to 38kV bus at dedicated 38kV feeder 5km
110/38kV grid station
-77 -
from 110/38kV source pry
Study 9 - Generator
Study 10 - Gen. connected to
connected midway along
38kV bus at remote pry
38kV circuit to remote pry
Figure 5.7: Savings in real power losses over 10-year period due to embedded generation
8000
7000
6000
Savings in real power losses (kw)
Case 2 - Direct conn to remote 10kV pry
5000
Case 3 - Dedicated feeder 5km from remote 10kV pry
Case 4L - Conn mid-trunk on longest 10kV feeder
4000
Case 5L - Conn to remote end of spur on longest 10kV
feeder
3000
Case 6L - Conn to trunk end of longest 10kV feeder
Case 8 - Dedicated 38kV feeder 5km from source pry
2000
Case 10 - Direct conn to 38kV bus at remote pry
1000
0
0
2
4
6
8
10
-1000
Year
-78 -
12
Figure 5.8: Savings in reactive power losses over 10-year period due to embedded generation
7000
6000
Savings in real power losses (kW)
Case 2 - Direct conn to remote 10kV pry
5000
Case 3 - Dedicated feeder 5km from remote pry
Case 4L - Conn mid-trunk on longest 10kV
feeder
4000
Case 5L - Conn to remote end of spur on
longest 10kV feeder
Case 6L - Conn to trunk end of longest 10kV
feeder
3000
Case 8 - Dedicated 38kV feeder 5km from
source pry
2000
Case 10 - Direct conn to 38kV bus at remote pry
1000
0
0
2
4
6
8
10
Year
-79 -
12
Table 5.12: Effect of Embedded Generator Location on Real Power Losses in Rural 110/38/10 KV Network over 10 Year Period
Embedded generator output = 2.5 MW in all cases
Annual growth rate = 4%
Rural 110/38/10 kV network
Power losses (kW) as a function of Embedded Generator location in years 0, 5 and 10
Year
0
5
10
0
5
10
0
5
10
0
5
10
0
5
10
Generator node
-
-
-
200
200
200
299
299
299
266
266
266
272A
272A
272A
110kV power loss (kW)
17
26
45
12
21
36
13
22
38
11
18
29
13
20
33
38kV power loss (kW)
221
360
669
136
239
468
151
264
514
121
201
332
148
219
403
10kV power loss (kW)
2146
3808
8890
2156
3813
8710
2340
4022
8899
770
1151
2021
1712
1583
3479
Total power loss (kW)
2384
4194
9604
2304
4072
9215
2504
4307
9452
903
1370
2383
2342
2217
4307
Study 1 - Base case
Study 2 - Direct
Study 3 - Dedicated gen.
Study 4 - Generator
Study 5 - Gen. connected to
connection of gen to
feeder 5km from remote
connected mid-trunk
remote end of mid-point spur
remote 10kV Pry
10kV Pry
-80 -
Rural 110/38/10 kV network
Power losses (kW) as a function of Embedded Generator location in years 0, 5 and 10
Year
0
5
10
0
5
10
0
5
10
0
5
10
0
5
10
Generator node
273
273
273
3100
3100
3100
3101
3101
3101
3102
3102
3102
100
100
100
110kV power loss (kW)
13
20
34
13
21
38
13
21
38
12
21
37
12
21
37
38kV power loss (kW)
156
228
412
220
359
665
230
368
674
184
308
583
148
257
469
10kV power loss (kW)
2173
1969
3861
2129
3778
8889
2186
3777
8850
2141
3814
8714
2165
3857
8742
Total power loss (kW)
2342
2217
4307
2361
4158
9592
2429
4166
9562
2338
4143
9334
2325
4135
9248
Study 6 - Gen. connected at Study 7 - Direct connection Study 8 - Gen connected via
remote end of trunk
of generator to 38kV bus at dedicated 38kV feeder 5km
110/38kV grid station
from 110/38kV source pry
-81 -
Study 9 - Generator
Study 10 - Gen. connected to
connected midway along
38kV bus at remote pry
38kV circuit to remote pry
Table 5.12 (continued): Effect of Embedded Generator Location on Reactive Power Losses In Rural 110/38/10 KV Network over 10 Year Period
Embedded generator output = 2.5 MW in all cases
Annual growth rate = 4%
Rural 110/38/10 kV network
Reactive power losses (kVAr) as a function of Embedded Generator location in years 0, 5 and 10
Year
0
5
10
0
5
10
0
5
10
0
5
10
0
5
10
Generator node
-
-
-
200
200
200
299
299
299
266
266
266
110kV power loss (kVAr)
631
999
1691
470
777
1378
495
825
1447
431
696
1112
503
754
38kV power loss (kVAr)
1049 1634
2812
778
1272 2211
828
1337
2325
732
1154 1804
844
1233 2039
10kV power loss (kVAr)
1498 2686
6379
1506 2684 6262 1801 3001
6551
436
745
272A 272A 272A
1269
1303 1229 1113 2529
Total reactive power loss (kVAr) 3178 5319 10882 2754 4734 9851 3124 5163 10323 1599 2594 4219 2576 3101 5837
Study 1 - Base case
Study 2 - Direct
connection of gen
Study 3 - Dedicated Study 4 - Generator
gen. feeder 5km
to remote 10kV Pry from remote 10kV
Pry
-82 -
Study 5 - Gen.
connected mid-
connected to
trunk
remote end of midpoint spur
Rural 110/38/10 kV network
Reactive power losses (kVAr) as a function of Embedded Generator location in years 0, 5 and 10
Year
0
5
10
0
5
10
0
5
10
0
5
10
0
5
10
Generator node
273
273
273
3100
3100
3100
3101
3101
3101
3102
3102
3102
100
100
100
110kV power loss (kVAr)
487
736
1253
474
797
1420
475
798
1424
470
791
1408
469
788
1379
38kV power loss (kVAr)
820
1210
2012
1045
1634
2781
1062
1649
2801
1006
1580
2690
971
1530
2213
10kV power loss (kVAr)
969
896
2285
1487
2666
6359
1526
2666
6350
1492
2685
6252
1511
2718
6283
Total reactive power loss (kVAr)
2576
3101
5837
3006
5097
10560
3063
5112
10575
2968
5056
10350
2951
5035
9875
Study 6 - Gen. connected Study 7 - Direct connection Study 8 - Gen connected
at remote end of trunk
Study 9 - Generator
Study 10 - Gen. connected
of generator to 38kV bus via dedicated 38kV feeder connected midway along to 38kV bus at remote pry
at 110/38kV grid station 5km from 110/38kV source 38kV circuit to remote pry
pry
-83 -
5.3.3
Analysis of 110/38/20 kV rural networks
Load flow and short circuit studies were undertaken for the representative 110/38/20 kV rural network similar to
those presented in Section 5.3 for the representative 110/38/10 kV rural network. The studies cover the same levels
of embedded generation located at similar locations addressing the same issues, such as the effect on power
imports, power losses, voltage regulation, overloads and fault levels. The results of the studies are presented in the
following set of tables:
Table 5.13 identifies the real and reactive power losses for the base case (i.e. with no embedded generation) and for
increasing levels of embedded generation up to 5 MW, with the generation located at points on the network
consistent with those studied in Section 5.3. The losses are converted into real and reactive power loss savings
compared with base case losses and the results are presented in Table 5.14, from which it is evident that the benefits
obtained from power loss savings resulting from embedded generation on the network are much lower with the
20 kV rural network than with the rural 10 kV network.
Table 5.15 summarises the effect of embedded generation on the network voltage profile. The table shows that in
all but two cases (i.e. study cases 5 and 6) the voltage across the network is controlled within +/-5 percent of
nominal. In case 5, with the generator connected at the end of a spur, voltage constraints prevent the connection of
generation of 2.5 MW and above. In case 6, with the generator connected at the end of the trunk of the 10 kV feeder,
voltage constraints prevent connection of the 5MW generator. The voltage constraints in each case are associated
with over voltages.
Table 5.16 confirms that in the base case and in the other cases with embedded generation connected to the system
there are no overloads on the representative network.
The results of short circuit analysis presented previously in Table 5.9 show that fault levels on the rural 110 kV, 38 kV
and 20 kV networks are increased only marginally by the presence of embedded generation and do not impinge on
the spare fault capacity.
The details of study results for the 110/38/20 kV rural network are presented in Appendix C.
-84 -
Table 5.13: Real power losses on the representative 110/38/20 kV rural network as affected by embedded generation
MW
gen
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
0
12
156
243
411
12
156
243
411
12
156
243
411
12
156
243
411
12
156
243
411
1
11
127
243
381
11
128
246
385
11
127
237
374
11
125
228
364
10
118
225
353
2.5
8
96
243
348
9
107
261
377
9
106
261
376
9
106
235
350
8
86
227
321
5
6
67
243
317
8
110
313
431
8
124
409
541
9
129
314
452
9
123
299
432
110kV
38kV
20kV
110kV
38kV
20kV
110kV
38kV
20kV
loss
loss
loss
loss
loss
loss
loss
loss
loss
Total
Total
110kV 38kV
Total
loss
loss
20kV
loss
110kV 38kV
Total
loss
loss
20kV
loss
Total
Study 2
Study 3
Study 4S
Study 4A
Study 4L
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
MW
gen
0
12
156
243
411
12
156
243
411
12
156
243
411
12
156
243
411
12
156
243
411
1
11
127
241
379
11
124
227
361
10
116
227
353
11
127
240
378
11
127
221
358
2.5
10
124
350
484
10
127
359
495
9
110
426
545
10
124
330
464
10
127
337
473
5
9
110kV
loss
136
38kV
loss
739
20kV
loss
884
151
38kV
loss
827
20kV
loss
988
197
38kV
loss
1099
20kV
loss
1308
714
20kV
loss
856
842
20kV
loss
1004
11
110kV
Total
loss
12
110kV
Total
loss
Total
9
133
110kV 38kV
loss
loss
Total
11
151
110kV 38kV
loss
loss
Total
Study 5S
Study 5A
Study 5L
Study 6S
Study 6A
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
MW
gen
0
12
156
243
411
12
156
243
411
12
156
243
411
12
156
243
411
12
156
243
411
1
10
116
212
338
11
156
242
409
11
157
242
410
11
144
240
395
11
132
245
388
2.5
9
105
333
447
9
156
241
406
9
163
247
419
8
130
242
381
8
105
245
358
5
12
110kV
loss
182
38kV
loss
881
20kV
loss
1075
155
38kV
loss
239
20kV
loss
401
180
38kV
loss
241
20kV
loss
427
244
20kV
loss
367
242
20kV
loss
327
Study 6L
6
110kV
Total
loss
Study 7
6
110kV
Total
loss
Study 8
-85 -
Total
6
117
110kV 38kV
loss
loss
Study 9
Total
6
79
110kV 38kV
loss
loss
Study 10
Total
Table 5.13 (continued): Reactive power losses on the representative 110/38/20 kV rural network as affected by embedded generation
MW
gen
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
0
446
742
139
1327
446
742
139
1327
446
742
139
1327
446
742
139
1327
446
742
139
1327
1
396
652
139
1187
397
654
144
1195
395
649
136
1179
392
644
132
1168
381
621
130
1133
2.5
332
550
138
1020
350
585
166
1102
349
583
148
1080
349
585
133
1067
305
518
129
952
5
234
110kV
loss
462
137
38kV 20kV
loss loss
833
310
110kV
loss
592
249
38kV 20kV
loss loss
1151
332
110kV
loss
633
231
38kV 20kV
loss loss
1195
343
110kV
loss
647
38kV
loss
177
20kV
loss
1167
334
110kV
loss
630
38kV
loss
169
20kV
loss
1133
Total
Total
Total
Total
Total
Study 2
Study 3
Study 4S
Study 4A
Study 4L
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
MW
gen
0
446
742
139
1327
446
742
139
1327
446
742
139
1327
446
742
139
1327
446
742
139
1327
1
395
650
137
1181
391
643
128
1163
373
615
125
1113
395
649
138
1182
391
647
127
1165
2.5
378
640
185
1203
382
647
182
1211
356
597
200
1152
377
637
188
1202
383
645
192
1220
5
359
110kV
loss
670
366
38kV 20kV
loss loss
1395
387
110kV
loss
713
384
38kV 20kV
loss loss
1484
466
110kV
loss
855
464
38kV 20kV
loss loss
1785
353
110kV
loss
660
38kV
loss
403
20kV
loss
1416
390
110kV
loss
715
38kV
loss
478
20kV
loss
1583
Total
Total
Total
Total
Total
Study 5S
Study 5A
Study 5L
Study 6S
Study 6A
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
MW
gen
0
446
742
139
1327
446
742
139
1327
446
742
139
1327
446
742
139
1327
446
742
139
1327
1
373
615
122
1110
399
741
139
1279
399
742
139
1280
399
725
138
1262
398
717
141
1256
2.5
344
580
190
1114
335
739
138
1212
336
751
142
1229
332
711
139
1182
332
686
141
1159
5
442
110kV
loss
814
38kV
loss
491
20kV
loss
1746
240
110kV
loss
737
38kV
loss
138
20kV
loss
1114
242
110kV
loss
763
38kV
loss
138
20kV
loss
1143
238
110kV
loss
698
38kV
loss
140
20kV
loss
1075
235
110kV
loss
659
38kV
loss
139
20kV
loss
1033
Study 6L
Total
Total
Study 7
Study 8
-86 -
Total
Study 9
Total
Study 10
Total
Table 5.14: Saving in real power losses on representative 110/38/20 kV rural network as affected by embedded generation
MW
gen
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
Real power loss (kW)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
29
-1
30
1
28
-4
26
1
30
6
37
1
31
14
47
2
38
17
58
2.5
4
60
0
63
3
49
-18
34
3
50
-18
35
3
50
8
61
4
71
15
90
5
6
110kV
loss
89
38kV
loss
0
20kV
loss
94
-70
20kV
loss
-20
-166
20kV
loss
-130
-71
20kV
loss
-41
-57
20kV
loss
-20
4
47
110kV 38kV
Total loss
loss
Study 2
MW
gen
0
0
32
1
33
2
30
1
1
30
1
2.5
2
32
-107
-73
5
3
110kV
loss
21
38kV
loss
-496
20kV
loss
-473
Real power loss (kW)
0
0
0
0
50
2
40
-116
-84
3
46
-584
20kV
loss
-577
16
1
6
110kV 38kV
Total loss
loss
Study 5S
Total
0
15
58
1
30
-183
-134
2
33
-856
20kV
loss
-897
0
-41
110kV 38kV
loss
loss
Total
0
33
1
30
-87
-52
2
30
-471
20kV
loss
-445
2
3
23
110kV 38kV
loss
loss
Total
Real power loss (kW)
0
0
0
1
5
110kV 38kV
loss
loss
Study 6S
Real power loss (kW)
Total
Study 4L
Real power loss (kW)
0
0
0
Study 5L
Real power loss (kW)
Total
3
33
110kV 38kV
loss
loss
Study 4A
Real power loss (kW)
0
0
0
Study 5A
Real power loss (kW)
Total
3
28
110kV 38kV
loss
loss
Study 4S
Study 3
Real power loss (kW)
0
0
0
0
MW
gen
Total
4
33
110kV 38kV
loss
loss
22
53
-94
-62
-599
20kV
loss
-592
Total
Study 6A
Real power loss (kW)
Real power loss (kW)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
2
40
31
73
1
0
1
2
1
-1
1
1
1
13
2
17
1
24
-2
23
2.5
3
52
-90
-36
3
1
2
6
3
-6
-4
-8
4
26
1
30
4
52
-2
53
5
0
110kV
loss
-26
38kV
loss
-638
20kV
loss
-664
3
20kV
loss
10
2
20kV
loss
-16
-1
20kV
loss
45
1
20kV
loss
84
Study 6L
6
1
110kV 38kV
Total loss
loss
Total
6
-23
110kV 38kV
loss
loss
Study 7
Study 8
-87 -
Total
6
40
110kV 38kV
loss
loss
Study 9
Total
6
77
110kV 38kV
loss
loss
Study 10
Total
Table 5.14 (continued): Saving in reactive power losses on representative 110/38/20 kV rural network as affected by embedded generation
MW
gen
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
50
90
0
140
49
88
-5
132
52
93
3
148
54
98
7
159
65
120
9
195
2.5
114
192
2
307
96
156
-27
225
98
158
-9
247
98
157
6
261
141
224
10
375
5
212
280
2
494
136
150
-109
176
115
109
-91
132
103
95
-38
160
112
112
-29
194
110kV
38kV
20kV
110kV
38kV
20kV
110kV
38kV
20kV
110kV
38kV
20kV
110kV
38kV
20kV
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
Total
Total
loss
Total
loss
Total
loss
Total
Study 2
Study 3
Study 4S
Study 4A
Study 4L
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
MW
gen
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
52
92
2
146
55
98
11
165
74
127
14
214
52
93
1
145
55
95
12
162
2.5
68
102
-46
124
64
95
-42
116
90
145
-61
175
69
105
-48
126
63
97
-52
107
5
87
72
-227
-68
59
29
-244
-157
-20
-113
-325
-458
93
81
-264
-89
57
26
-338
-256
110kV
38kV
20kV
110kV
38kV
20kV
110kV
38kV
20kV
110kV
38kV
20kV
110kV
38kV
20kV
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
Total
loss
Total
loss
Total
loss
Total
loss
Total
Study 5S
Study 5A
Study 5L
Study 6S
Study 6A
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
Reactive power loss (kVAr)
MW
gen
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
74
127
17
217
47
1
0
48
47
0
0
47
47
17
1
65
48
25
-1
71
2.5
102
162
-50
213
111
3
1
115
110
-9
-3
98
114
30
1
145
115
55
-1
168
5
4
-72
-351
-419
206
5
2
213
204
-21
1
184
209
44
-1
252
211
83
0
294
110kV
38kV
20kV
110kV
38kV
20kV
110kV
38kV
20kV
110kV
38kV
20kV
110kV
38kV
20kV
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
loss
Study 6L
Total
Study 7
Total
Study 8
-88 -
Total
Study 9
Total
loss
Study 10
Total
Table 5.15: Summary of embedded generation effects on 110/38/20 kV rural network voltage
Study
EG location
Comment on voltage effects
Base case (No EG)
Voltage controlled within limits for embedded generation
Case
No.
1
up to 5 MW
2
3
3
5
EG connected direct to 20 kV bus at
Voltage controlled within limits for embedded generation
remote primary
up to 5 MW
EG 5 km from remote with direct
Voltage controlled within limits for embedded generation
connection to 20 kV bus
up to 5 MW
EG connected mid-trunk on
Voltage controlled within limits for embedded generation
outgoing 20 kV feeders
up to 5 MW
EG connected at end of spur on
Voltage constraints prohibit connection of 2.5 MW
outgoing 20 kV feeder
generator (to average and longest feeders) and 5 MW
generator (to shortest, average and longest feeders) at this
location
6
7
8
9
EG connected at end of trunk on
Voltage constraints prohibit connection of 5MW generator
outgoing 20 kV feeder
to shortest, average and longest feeders
EG direct connection to source 38 kV
Voltage controlled within limits for embedded generation
bus
up to 5 MW
EG 5 km from source with direct
Voltage controlled within limits for embedded generation
connection to 38 kV bus
up to 5 MW
EG connected midway along 38 kV
Voltage controlled within limits for embedded generation
feeder between source substation &
up to 5 MW
remote primary
10
EG connected direct to 38 kV bus at
Voltage controlled within limits for embedded generation
remote primary
up to 5 MW
-89 -
Table 5.16: Summary of embedded generation effects on 110/38/20 kV rural network circuit
loadings (i.e. utilisation).
Study
EG location
Comment on
Case No.
equipment utilisation
1
Base case (No EG)
2
EG connected direct to 20 kV bus at remote primary
3
EG 5 km from remote with direct connection to 20 kV bus
3
EG connected mid-trunk on outgoing 20 kV feeders
5
EG connected at end of spur on outgoing 20 kV feeder
6
EG connected at end of trunk on outgoing 20 kV feeder
7
EG direct connection to source 38 kV bus
8
EG 5 km from source with direct connection to 38 kV bus
EG connected midway along 38 kV feeder between source substation &
9
remote primary
10
5.4
No overloads
EG connected direct to 38 kV bus at remote primary
Analysis of 110/38/10 kV semi-urban networks
The corresponding results for this representative network identifying losses, loss savings, voltage constraints and
circuit utilisation are presented in Tables 5.17 to 5.20 respectively. A complete set of results is presented in
Appendix C.
The studies show that loss savings with this representative network are relatively small. It is also evident that the
voltage profile is maintained within the +/-5 percent limits and in most cases much closer than that to the nominal
voltage. Additionally, except in those cases where a 5 MW generator is connected at the end of a spur or the trunk of
the 10 kV feeder, the network is not overloaded. In exceptional cases where the generator is overloaded the
overload is only minimal, i.e. estimated at about 1 percent.
-90 -
Table 5.17 : Real power losses as affected by embedded generation at 10 kV
MW Real power loss Real power loss Real power loss Real power loss Real power loss Real power loss Real power loss Real power loss Real power loss Real power loss Real power loss
gen
(kW)
(kW)
(kW)
(kW)
(kW)
(kW)
(kW)
(kW)
(kW)
(kW)
(kW)
0
29
29
29
29
29
29
29
29
29
29
29
1
28
34
26
24
19
26
21
16
27
22
16
2.5
28
61
30
25
18
33
33
35
37
33
38
5
28
161
59
46
56
75
115
161
95
130
178
Study 2
Study 3
Study 4S
Study 4A
Study 4L
Study 5S
Study 5A
Study 5L
Study 6S
Study 6A
Study 6L
Table 5.17 (continued): Reactive power losses as affected by embedded generation at 10 kV
MW Reactive power Reactive power Reactive power Reactive power Reactive power Reactive power Reactive power Reactive power Reactive power Reactive power Reactive power
gen
loss (kVAr)
loss (kVAr)
loss (kVAr)
loss (kVAr)
loss (kVAr)
loss (kVAr)
loss (kVAr)
loss (kVAr)
loss (kVAr)
loss (kVAr)
loss (kVAr)
0
22
22
22
22
22
22
22
22
22
22
22
1
18
23
17
16
14
17
15
13
17
15
13
2.5
14
44
15
13
12
17
17
20
18
19
21
5
13
123
25
20
24
33
51
71
42
57
78
Study 2
Study 3
Study 4S
Study 4A
Study 4L
Study 5S
Study 5A
Study 5L
Study 6S
Study 6A
Study 6L
-91 -
Table 5.18: Savings in real power losses as affected by embedded generation at 10 kV
Real power
Real power
Real power
Real power
Real power
Real power
MW gen
loss (kW)
loss (kW)
Real power loss Real power loss Real power loss Real power loss Real power
(kW)
(kW)
(kW)
(kW)
loss (kW)
loss (kW)
loss (kW)
loss (kW)
loss (kW)
0
0
0
0
0
0
0
0
0
0
0
0
1
0
-5
2
5
10
3
7
13
2
7
13
2.5
1
-32
-1
4
10
-4
-5
-7
-9
-4
-9
5
1
-132
-30
-17
-27
-46
-86
-132
-66
-101
-149
Study 2
Study 3
Study 4S
Study 4A
Study 4L
Study 5S
Study 5A
Study 5L
Study 6S
Study 6A
Study 6L
Table 5.18 (continued): Savings in reactive power losses as affected by embedded generation at 10 kV
Reactive
Reactive
power loss
power loss
MW gen
(kVAr)
(kVAr)
loss (kVAr)
loss (kVAr)
loss (kVAr)
0
0
0
0
0
0
1
4
-2
4
6
8
Reactive
Reactive
Reactive
Reactive
Reactive
power loss
power loss
power loss
power loss
power loss
loss (kVAr)
(kVAr)
(kVAr)
(kVAr)
(kVAr)
(kVAr)
0
0
0
0
0
0
5
7
9
4
6
9
Reactive power Reactive power Reactive power Reactive power
2.5
7
-22
7
9
10
5
5
2
3
3
1
5
9
-101
-3
2
-3
-11
-29
-49
-20
-35
-56
Study 2
Study 3
Study 4S
Study 4A
Study 4L
Study 5S
Study 5A
Study 5L
Study 6S
Study 6A
Study 6L
-92 -
Table 5.19: Summary of embedded generation effects on 110/38/10 kV semi-urban network
voltage
Study
EG location
Comment on voltage effects
Case
No.
1
Base case (No EG)
2
EG connected direct to 10 kV bus at
remote primary
3
EG 5 km from remote with direct
connection to 10 kV bus
3
EG connected mid-trunk on
outgoing 10 kV feeders
5
EG connected at end of spur on
outgoing 10 kV feeder
6
Voltages controlled within +/- 5 percent of nominal in all
cases.
EG connected at end of trunk on
outgoing 10 kV feeder
7
EG direct connection to source 38 kV
bus
8
EG 5 km from source with direct
connection to 38 kV bus
9
EG connected midway along 38 kV
feeder between source substation &
remote primary
10
EG connected direct to 38 kV bus at
remote primary
-93 -
Table 5.20: Summary of embedded generation effects on 110/38/10 kV semi-urban network circuit
loadings (i.e. utilisation).
Study
EG location
Comment on
Case No.
equipment utilisation
1
Base case (No EG)
2
EG connected direct to 10 kV bus at remote primary
3
EG 5 km from remote with direct connection to 10 kV bus
3
EG connected mid-trunk on outgoing 10 kV feeders
5
EG connected at end of spur on outgoing 10 kV feeder
6
EG connected at end of trunk on outgoing 10 kV feeder
7
EG direct connection to source 38 kV bus
8
EG 5 km from source with direct connection to 38 kV bus
9
EG connected midway along 38 kV feeder between source substation &
Only minor overload
(1%) when 5 MW
generator located at
end of trunk on longest
10 kV feeder (case 6)
remote primary
10
5.5
EG connected direct to 38 kV bus at remote primary
Analysis of 110/38/10 kV dense urban networks
The corresponding results for this representative network that identify losses, loss savings, voltage constraints and
circuit utilisation are presented in Tables 5.21 to 5.24 respectively. A complete set of results is presented in
Appendix C.
The studies show that loss savings with this representative network are again relatively small. Again the voltage
profile is maintained within the +/-5 percent limits and in most cases much closer than that to the nominal voltage.
The network is not overloaded.
-94 -
Table 5.21: Real power losses as affected by embedded generation at 10 kV
MW
Real power
Real power
gen
loss (kW)
loss (kW)
(kW)
(kW)
(kW)
(kW)
(kW)
(kW)
(kW)
(kW)
(kW)
0
28
28
28
28
28
28
28
28
28
28
28
1
28
34
27
26
20
27
26
14
27
26
18
2.5
28
52
29
29
13
31
33
11
35
37
11
5
Real power loss Real power loss Real power loss Real power loss Real power loss Real power loss Real power loss Real power loss Real power loss
28
158
41
49
18
56
76
54
75
93
27
Study 2
Study 3
Study 4S
Study 4A
Study 4L
Study 5S
Study 5A
Study 5L
Study 6S
Study 6A
Study 6L
Table 5.21 (continued): Reactive power losses as affected by embedded generation at 10 kV
MW Reactive power Reactive power Reactive power Reactive power Reactive power Reactive power Reactive power Reactive power Reactive power Reactive power Reactive power
gen
loss (kVAr)
loss (kVAr)
loss (kVAr)
loss (kVAr)
loss (kVAr)
loss (kVAr)
loss (kVAr)
loss (kVAr)
loss (kVAr)
loss (kVAr)
loss (kVAr)
0
12
12
12
12
12
12
12
12
12
12
12
1
18
23
18
17
20
17
17
17
18
17
19
2.5
17
44
17
17
11
18
19
10
20
21
10
5
13
121
19
22
9
26
34
25
34
42
13
Study 2
Study 3
Study 4S
Study 4A
Study 4L
Study 5S
Study 5A
Study 5L
Study 6S
Study 6A
Study 6L
-95 -
Table 5.22: Savings in real power losses as affected by embedded generation at 10 kV
Real power
Real power
Real power loss Real power loss Real power loss Real power loss Real power
MW gen
loss (kW)
loss (kW)
(kW)
(kW)
(kW)
(kW)
0
0
0
0
0
0
0
1
0
-5
1
2
8
1
Real power
Real power
Real power
Real power
loss (kW)
loss (kW)
loss (kW)
loss (kW)
loss (kW)
0
0
0
0
0
2
14
1
2
11
2.5
0
-24
-1
-1
15
-3
-5
17
-7
-9
18
5
0
-129
-13
-20
10
-28
-48
-26
-47
-65
1
Study 2
Study 3
Study 4S
Study 4A
Study 4L
Study 5S
Study 5A
Study 5L
Study 6S
Study 6A
Study 6L
Reactive
power loss
(kVAr)
0
-6
2
-13
Study 5L
Reactive
power loss
(kVAr)
0
-6
-8
-22
Study 6S
Reactive
power loss
(kVAr)
0
-5
-9
-30
Study 6A
Reactive
power loss
(kVAr)
0
-7
2
-1
Study 6L
Table 5.22 (continued): Savings in reactive power losses as affected by embedded generation at 10 kV
Reactive
power loss
(kVAr)
MW gen
0
0
1
-6
2.5
-5
5
-1
Study 2
Reactive
power loss
(kVAr)
0
-11
-32
-109
Study 3
Reactive
power loss
(kVAr)
0
-6
-5
-7
Study 4S
Reactive
power loss
(kVAr)
0
-5
-5
-10
Study 4A
Reactive
power loss
(kVAr)
0
-8
1
3
Study 4L
Reactive
power loss
(kVAr)
0
-6
-6
-14
Study 5S
-96 -
Reactive
power loss
(kVAr)
0
-5
-7
-22
Study 5A
Table 5.23: Summary of embedded generation effects on 110/38/10 kV dense urban network
voltage
Study
EG location
Comment on voltage
effects
Case
No.
1
Base case (No EG)
2
EG connected direct to 10 kV bus at remote primary
3
EG 5 km from remote with direct connection to 10 kV bus
3
EG connected mid-trunk on outgoing 10 kV feeders
5
EG connected at end of spur on outgoing 10 kV feeder
Voltages controlled
within +/- 5 percent of
6
EG connected at end of trunk on outgoing 10 kV feeder
7
EG direct connection to source 38 kV bus
8
EG 5 km from source with direct connection to 38 kV bus
9
EG connected midway along 38 kV feeder between source substation &
remote primary
10
EG connected direct to 38 kV bus at remote primary
-97 -
nominal in all cases.
Table 5.24: Summary of embedded generation effects on 110/38/10 kV dense urban network
circuit loadings (i.e. utilisation).
Study
EG location
Comment on equipment
Case No.
utilisation
1
Base case (No EG)
2
EG connected direct to 10 kV bus at remote primary
3
EG 5 km from remote with direct connection to 10 kV bus
3
EG connected mid-trunk on outgoing 10 kV feeders
No overloads, although
with the 5 MW generator
5
EG connected at end of spur on outgoing 10 kV feeder
6
EG connected at end of trunk on outgoing 10 kV feeder
7
EG direct connection to source 38 kV bus
8
EG 5 km from source with direct connection to 38 kV bus
9
EG connected midway along 38 kV feeder between source substation &
connected to outgoing
10 kV feeders the loading
on the cable where the
generator is connected
may be fully loaded,
particularly cases 5 and 6.
remote primary
10
EG connected direct to 38 kV bus at remote primary
-98 -
6.
Embedded Generation Benefit Calculation Methodology
6.1
Introduction
The previous sections have qualitatively identified the costs and benefits associated with the connection of
embedded generation to the distribution network in Ireland. This qualitative assessment provided the basis for the
cost / benefit and established a preliminary scope of the areas that the costs / benefit will arise. These areas can
roughly be split into three categories:
•
Revenue or operational;
•
Capital or asset;
•
Service or customer related.
The intent behind this section is to develop a methodology for the quantification of these costs and benefits within
the context of the Irish electricity market. Further, examples will be calculated using the findings from the
representative network modelling studies to illuminate the calculation methodology and to provide a sense of scale
and gain an understanding of the relative order of importance of the respective costs / benefits.
6.2
Approach
The approach adopted to establish the calculation methodology has incorporated the various benefits within a
series of logical groupings. This approach will reduce the possibility of double counting and is intended to allow
visibility of the revenue, capital and service costs / benefits independently of one another.
Revenue Costs and Benefits include:
•
Energy Losses
•
Emissions Benefits
•
Avoided Use of System charges
•
Energy Price Benefits
Capital Costs and Benefits include:
•
Displaced System Plant
•
Asset Benefit – deferred reinforcement;
•
Displaced Load
•
Initial Connection Costs;
-99 -
Service Costs and Benefits include:
•
Customer Minutes Lost
•
Voltage Support and Reactive Power Provision;
•
Social benefit to local community;
The methodology takes into account the existing Least Cost Technically Acceptable Solution approach to the
derivation of the connection point and connection costs for embedded generation to connect to the ESB
distribution network. The LCTAS provides the starting point for any and all of the additional calculations to
determine the value of the identified benefits and a context within which the calculations can be formulated.
In order that the methodology can provide a pragmatic solution a number of simplifying assumptions have been
made. These are identified and discussed within the context of the relevant part of the methodology and where it is
seen that there could be differences in opinion on the approach adopted we have flagged this as a potential issue
and drawn these issues out within a separate sub-section.
Wider macro economic issues are considered to be outside the scope of this study, however, where these arise we
have endeavoured to quantify the impact as far as reasonably practicable. Further, it should be noted that should
elements of this methodology be subsequently adopted, additional costs will be incurred in the connection design
and planning process. Estimation and suggested treatment of these costs are out with the scope of this report.
-100 -
6.3
Key to symbols
The methodology is presented as a process flow diagram with supporting descriptive text that outlines the
functionality of each of the steps involved. The process diagrams used a series of symbols and these are identified
and described below:
Symbol
Description
This signifies a link to another process within the methodology. There are two types of link
–coloured green to show a link into the process, and coloured red / orange to show a link
[11]
from the process.
These have been used to enable the separate elements of the calculation methodology to
be self-contained within the overall process. These links are in numbered pairs to show
where they come from or go to.
This signifies data that is required to support the calculation to be made. Such data may
Security
Standards
comprise statements of policy, financial assumptions, technical specifications and market
pricing / tariffs etc.
This signifies a process step. These are numbered sequentially to signify the flow in the
2
Determine
Displaced
Load
process with the numbering being restarted for each process.
Each step involves a specific task or calculation in the process. The steps are described
within the process description.
Response
Acceptable?
This signifies a decision point in the process. The process routing from this step will follow
either a ‘Yes’ or ‘No’ direction.
Connection
Commissioned
Signifies the end of the process.
1
Connection
Application
Signifies the start of the process.
3
Determine
LCTAS
This signifies a predefined process. This symbol is used within the overview process flow
diagram to represent the various sub calculation processes that are defined within the
methodology.
-101 -
6.4
Connection Methodology Functional Overview
This process provides an overview of the proposed methodology, incorporating the existing connection application,
offer and dispute processes. It begins with the applicant submitting their application for connection to ESB
Networks – Step 1. This is the trigger for the whole process.
Prior to this present piece of work only those costs associated with the physical connection to the distribution
network – specifically the connection assets / reinforcement that is required to enable such connection. However,
this calculation methodology identifies those areas impacted due to the connection of the embedded generation to
the distribution network. These areas will include, not only the connection asset costs, but also any benefits that
may arise from system annual energy and peak loss reduction, avoided emissions from system generation plant,
social benefits, improvements to the quality of supply etc.
It is recognised that the connection of embedded generation does not guarantee that benefits are created, indeed it
may be the case that such an embedded generation plant may compound losses already existing on the distribution
or even create additional cost in the wholesale electricity market though less efficient operation of system thermal
power plant. All of these elements are individually considered within the framework of the methodology outlined
within this process. It should be noted that the Transmission system costs and benefits are considered within the
“Displaced System Plant Costs” and “Commercial Benefits” processes.
6.4.1
Inputs
Application for connection of embedded generation plan to the ESB Networks distribution system submitted by the
Applicant;
6.4.2
Outputs
Net benefit of connection of the embedded generation plant to the ESB Networks distribution system.
6.4.3
Participants
Applicant; ESB Networks / ESB National Grid
-102 -
2b
1
Connection
Application
ESB NG
Applicant
Connection Methodology Functional Overview
Connection Offer
Received
Offer
Acceptable?
3b
Trans.
System
Data
2
Application
Received &
Logged
3a
4
Energy
Price
Benefit
6
Voltage
Benefit
5
Loss
Benefit
4
Dispute
Connection
Offer
2a
Yes
3
Determine
LCTAS
ESB Networks
Distribution
System
Data
No
5
8
Asset
Benefit
7
Connection
Built
10
Emissions
Benefit
12
Fuel Benefit
9
Transmission
Benefit
7
CML Benefit
6
Acceptance
Received and
Logged
8
9
Connection
Commissioned
11
Social
Benefit
10
11
12
13
Sum All
Benefits
-103 -
Combined
Benefit
6.4.4 Connection Methodology: Process Description
Step
1
Name
Connection
From
To
Applicant
ESB
The Applicant will complete the necessary information request forms – CX51C_150 and
Networks
provide all relevant data in relation to the proposed equipment to be connected to the
Application
Description
Data Sources
distribution system to allow ESB Networks to undertake the studies and costing
exercises necessary to provide a connection offer to the Applicant.
2
Application Received
and Logged
3
Determine LCTAS
ESB
ESB
Networks
Networks
ESB Networks receive the formal request and provide confirmation in the form of an
ESB
ESB
This process is undertaken by ESB Networks to determine the connection solution that
Applicant Application form
Networks
Networks
is technically acceptable and which results in the least cost being incurred by the DSO.
and supporting information;
Any costs incurred by ESB Networks in providing a connection or installing
Distribution system data;
infrastructure which are deemed to be over and above the LCTAS are presently borne in
Transmission system data;
acknowledgement letter to the Applicant.
full by the customer or developer.
4
Displaced Energy
Benefit
ESB
Networks
ESB NG
The connection and operation of embedded generation plant within the distribution
Transmission System Data;
network will affect the operation of transmission system connected generation plant
System generation plant
due to system demand being reduced through the embedded generation offsetting
data;
local system demand.
Ancillary Service Contracts
The outcome of this is that the system plant may incur additional costs (due to reduced
data;
operating efficiency); there may be a net benefit on the transmission system losses or
benefit from deferred load related capital expenditure.
The purpose of this process is to assess the extent of any differential in the cost of
generating the embedded generation and the cost of providing the energy from a
system generation plant.
50
As identified in “Guide to the Process for Connection to ESB’s Distribution System”, Revision 1, February 2002.
-104 -
6.4.4 Connection Methodology: Process Description (cont.)
Step
5
6
Name
From
To
Description
Data Sources
Loss Benefit
ESB
ESB
The purpose of this process is to determine the impact of the embedded generation on
System Generation Plant
Calculation
Networks
Networks
the distribution system losses. It is likely that there will be a positive benefit through the
Costs
reduction in peak system capacity required to service the distribution network demand
Distribution System data
and reduced cost in terms of annual energy loss as the load is being supplied locally.
Load duration data
The output of this process is a net value for any benefit deriving from the operation of
System loss data (energy
the embedded generator.
and kW)
This process is to determine the impact of the embedded generation on the distribution
Reactive power costs
system power factor and voltage support. The connection of embedded generation
Distribution system data
may result in a net benefit of cost depending on the network configuration and its
Load duration data
Voltage Benefit
ESB
ESB
Networks
Networks
connection point into the system.
The output of this process will be a benefit value arising from any avoided / deferred
capital expenditure due to improved pf and any saving in the cost of reactive energy
required by the system.
7
CML Benefit
ESB
ESB
Networks
Networks
This process is to determine the impact of the embedded generation on the distribution
Load duration curves;
system reliability and security of supply. Any reduction in CMLs will arise from
Network statistical fault
providing an ‘islanding’ scheme for the embedded generator to provide alternative
probabilities (SAIFI, SAIDI);
electricity supply during system fault conditions.
Operational restoration
schemes;
8
Asset Benefit
ESB
ESB
Networks
Networks
This will provide a benefit calculation on the basis that the embedded generation defers
Load duration curve for
the need to replace assets either as a result of reduced thermal loading or releasing
network;
network capacity that can be used to support load growth. The asset benefit related to
Forecast generation profile
reduced system peak losses is accounted for within the Losses calculation process.
Forecast load growth;
Asset replacement costs;
-105 -
6.4.4 Connection Methodology: Process Description (cont.)
Step
9
Name
From
To
Transmission Benefit
ESB NG
ESB NG
Description
Data Sources
This process will determine the impact of the embedded generation on the
transmission system through reduced losses and capital expenditure deferment
through changes in the timing of system reinforcement.
10
Emissions Benefit
ESB
ESB
Networks
Networks
This process will provide a value for any benefit from reduced environmental emissions.
System generation emission
Those emissions considered are CO2 (EU ETS costs), NOX and SOX.
data;
Generation plant emission
data;
Emission Costs;
11
Social benefit
To calculate the extent of any social benefits that will derive from the installation of the
embedded generation. This is driven by the impact of the embedded generation on
local jobs.
12
Fuel Benefit
This process will calculate the quantity of fuel that is saved / displaced as a result of the
embedded generation operation. This will be derived from the avoided system plant
and the embedded generation operation profile.
13
Sum All Benefits
The combined benefit calculation is a summation of the various benefits calculated
within items 4 through 12. These will be summated and the cost of the connected
subtracted to determine the net benefit of the embedded generation.
-106 -
6.5
Least Cost Technically Acceptable Solution (LCTAS) Process
The developer of the embedded generation (the Applicant) will need to approach the DNO in order to receive a
formal quotation for the connection of their proposed generation plant to the distribution network. Typically the
process would involve the request for budget connection offer followed by a formal offer when the developer is
finalising the project costing. The LCTAS approach will identify the point of connection and any additional works
required on the distribution network to enable the embedded generator to be connected whilst maintaining the
quality of supply and network operational stability.
The strength of the distribution network is directly related to the short circuit level. Higher short circuit levels give an
electrically stronger network more able to deal with disturbances arising from switching transients (e.g. generators
coming on or off load, motors and other reactive elements of the network). The connection of an embedded
generator to the distribution network will contribute to the short circuit level (inter alia – fault level). In some
situations the existing fault level is approaching the switchgear rating on the network and the connection of the
embedded generation may require this equipment to be upgraded due to the increased fault level following
connection.
Each connection application demands that the DNO examines the impact the new generation will have on the
network in order to confirm that the network and other customers connected to the network will not be adversely
affected by the presence of the new generation. In addition to the system planning studies that the DNO would
normally perform, such as base case load flow, contingency load flow and short circuit analysis, the DNO has to be
satisfied that the step change voltage limits are not exceeded when the embedded generation is suddenly switched
on or switched off the network. Other technical aspects that are examined include harmonics, losses and network
protection.
The costs of these additional system planning requirements cannot be easily determined, however, the activity that
has been undertaken in assessing the representative network segments for the SEI Study will provide an indication
on the time required to complete such studies. This should enable resourcing costs to be determined. Such costs
are assumed to be recovered on a case-by-case basis from the developer and therefore form part o the overall
connection costs for the generation plant.
6.5.1
Inputs
Connection Application; Machine Performance Data; DNO Network Data; Equipment Pricing
6.5.2
Outputs
Connection Offer to Applicant; Network Model without Generator; Network Model with Generator
6.5.3
Participants
ESB Networks
-107 -
LCTAS
3a
Model
without
Generator
1
Network Model
w/o generator
3b
Short Circuit
Capability
Voltage Level
Assessment
Network
Loading
Studies
Protection
Studies
ESB Networks
Substation
Capacity
Equipment
Prices
Supply Quality
10
Connection
Offer Issued
9
Connection
Pricing
3
Determine
Connection Point
No
4
Determine
Connection
Location
5
Connection
Design
6
Compliance
with stds?
8
Network Model
with generator
Yes
No
7
Least Cost?
Model with
Generator
6.5.4
hhhh
-108 -
6.5.4 LCTAS: Process Description:
Step
1
Name
Network Model without
Generator
From
To
Description
ESB
ESB
ESB will create a model of the distribution network as it is before the connection of
Networks
Networks
Data
Distribution Network Data
the embedded generator. This model will subsequently be used as the baseline
network model.
2
Short Circuit
ESB
ESB
Voltage Level
Networks
Networks
These studies all form part of the process undertaken in determining the least cost
Demand Load Profiles
technically acceptable solution for the connection of the embedded generation.
Network Plan
Network Loading
The details of these studies and their implementation will be covered within
Protection Studies
internal ESB business policy and procedural documentation. Review of this
Substation Capacity
documentation is outside the scope of this study.
Supply Quality
3
Determine Connection
Point
ESB will need to make a judgement as to the most appropriate point for the
ESB Statutory Obligations
connection of the embedded generation to the distribution network on the basis
ESB Connection Policy
of the results of the studies undertaken in step 2 above. Such a decision will be
driven by the statutory obligations on ESB to maintain the quality and reliability of
the electricity supplied from the distribution network.
4
Determine Connection
Location
ESB
ESB
Networks
Networks
The connection point will provide the electrical solution for the connection to the
Land topography;
distribution system. The next step is to determine the physical location of the
Land Ownership records;
connection. There will be consideration required of the availability of land, local
geography etc. It is likely that there will be a degree of compromise required in
determining the final physical location for the connection and subsequent
amendment to the network model to reflect the final electrical connection point.
5
Connection Design
ESB
ESB
Networks
Networks
The connection will now undergo detailed design to ensure that it satisfies the ESB
standards for the LCTAS and that the connection provides the level of reliability
that is being requested in the connection application.
6
Compliant with
Standards?
ESB
ESB
Networks
Networks
The connection design needs to satisfy the relevant standards. To the extent that
it does not then the connection needs to be re-designed.
-109 -
ESB Construction Standards
Step
7
8
Name
Least Cost?
Network Model with
Generator
From
To
ESB
ESB
Networks
Networks
ESB
ESB
Networks
Networks
Description
Data
Does this design comprise the least cost solution? If not then the design needs to
be revisited.
Once the connection design has been determined to be compliant with the LCTAS
policy the Network model should be updated to incorporate the embedded
generator and the new connection assets and any reinforcement to be
undertaken as a consequence of the new connection.
This revised Network Model with the embedded generation will be used in the
benefit calculations.
9
Connection Pricing
Once the connection point has been finalised and the connection design is
detailed the formal offer will be priced against a current equipment price database
and a bill of quantities collated for the connection.
10
Offer Issued
The connection offer is issued to the Applicant
-110 -
Current Equipment Prices
6.6
Connection Offer Dispute
This process briefly describes the steps involved should an Applicant dispute a connection offer made by ESB
Networks for the connection of an embedded generator to the ESB distribution network. This process has been
incorporated for the sake of completeness. This process description does not specify particular timescales by which
the various activities must be completed.
6.6.1
Inputs
Details of connection offer under dispute; ESB justification
6.6.2
Outputs
CER decision on connection offer
6.6.3
Participants
Applicant; ESB Networks; CER; External consultants
-111 -
Connection Offer - Dispute
1
Receive
Disputed Offer
2
Obtain
Benchmark
Pricing
3
Request
Justification of
Offer
5
Consider
Response
CER
2a
6
Response
Acceptable?
Yes
10
Dispute
Over-ruled
No
7
Dispute Upheld
ESB Networks
4
Provide
Justification
8
Offer Amended
9
Offer Re-issued
Offer Stands
2b
-112 -
6.6.4
Process Description:
Step
1
Name
Receive Disputed Offer
From
To
Description
Applicant
CER
The Applicant forwards the full details of the connection offer that they
Data Sources
ESB Networks Connection offer
are disputing with ESB Networks, to the CER.
2
Obtain Benchmark Pricing
CER
CER
The CER retains a number of technical consultants to support them in
External Consultants
determining such disputes. The CER will, where it deems it is
CER data base of costs (if this exists)
necessary, obtain reference pricing for similar connections from
external consultants that have recent experience in construction,
design or tender adjudication of equivalent distribution network
connections.
3
Request Justification of
CER
Offer
ESB
Where there are items that have a significant variance between the
Networks
benchmark cost and the price included for that element within the
connection offer, the CER will request a justification of the difference
from ESB Networks.
4
Provide Justification
ESB
CER
Networks
ESB Networks must provide a reasoned justification for the variance in
Internal ESB Networks cost data;
cost for those items identified by the CER. This justification may be
External tender documentation;
subject to specific deadlines for response to CER.
5
Consider Response
CER
CER
CER shall consider the ESB Networks justification and may use external
technical consultants to assist in this decision making process.
6
Response Acceptable?
CER
CER
CER will, following consideration of the ESB response, determine
whether the reasons provided in support of the connection pricing by
ESB are acceptable.
6
Dispute Upheld
CER
ESB
Networks
Following due consideration of the ESB Networks justification, the CER
may find that the dispute was justified and instruct ESB Networks to
amend its connection offer to be in line with the benchmarked pricing.
-113 -
Step
7
8
Name
Offer Amended
Offer Re-issued
From
To
Description
ESB
ESB
Networks
Networks
ESB Networks will amend its connection offer to bring it into line with
the decision by the CER.
ESB
Applicant
Self explanatory
Applicant
CER may find that the cost structure reflected within the disputed
Networks
9
Dispute Over-ruled
CER
connection offer is fair and presents cost that will be properly incurred
in the process of providing the connection to the ESB distribution
system. The CER will inform the Applicant and ESB Network of this
decision.
10
Offer Stands
ESB
Networks
ESB Networks needs take no further action prior to receipt of formal
acceptance of the connection offer by the Applicant.
-114 -
Data Sources
6.7
Displaced Energy Benefit
Many embedded generation technologies have a unit cost of generation that is driven by their high initial capital
cost, while large fossil fuel plant generation cost is more closely linked to fuel costs. This currently result in higher
unit generation costs for embedded generation. Capital costs for many embedded generation plants are expected
to fall, which will drive down the unit cost and reduce this cost differential.
Care needs to be taken when comparing plant simply by the unit cost of generation, which describes the cost of
putting each kilowatt-hour onto the system. For deeply embedded generation (egg. Solar PV serving a building or
small CHP), this is also the cost of each kilowatt-hour delivered to the customer, since the transmission and
distribution systems are not used. By contract, a large centrally located plant will also have the delivery costs of
using the transmission and distribution systems, and the losses associated with these. The cost / benefit issues
associated with the distribution system and transmission system energy losses are captured within the other parts of
the calculation methodology and it is only the displaced energy that is considered in this calculation process.
This process uses the embedded generation operating profile to determine which type of system plant will be
displaced and the quantity of system generation plant energy displaced will be the difference between the ‘before’
and ‘after’ annual energy off-take at the transmission system exit point in question.51 The calculations will be done
for the first year of operation of the embedded generation plant with the results of the calculations then being
projected over an agreed period – currently assumed to be 15 years.
6.7.1
Inputs:
Network Model without Generation; Network Model with Generation; Embedded Generation Price
6.7.2
Outputs:
Net Energy Benefit
6.7.3
Participants:
ESB Networks
51
It is noted here that the Market Arrangements for Electricity are presently under discussion prior to implementation in 2005. This
envisages use of Locational Marginal Pricing for the wholesale market and therefore any benefit calculation under the MAE will
need to take this into consideration.
-115 -
Energy Price Benefit
ESB Networks
4
1
Saving in Annual
System
Generation
2
Determine System
Displaced Plant
3
Determine Value
of Displaced
Energy
4
Calculate Cost of
embedded
generation output
Displaced
Energy
Price
Embedded
Generation
Price
Network
Model
(without
Gen)
Network
Model With
Generation
Demand
Load Profile
-116 -
5
Calculate Net
Energy Benefit
4
6.7.4
Process Description:
Step
Name
1
Determine Saving in
Annual System Generation
From
To
Description
Data
ESB
ESB
The extent of the energy saved in supplying the off-take requirement at the relevant
Embedded Generation
Networks
Networks
transmission exit node will be dependant on the operating profile of the embedded
Profile
generation and the distribution load profile of the connected customer demand
System Load Profile
supplied from that exit point. The saving in the energy required will be the change in
the annual energy off-take at that exit point following connection of the embedded
generation.
Energy Off-take (no Gen) = System Load Factor * Peak kW
Embedded Generation Output = Embedded Plant Capacity (MW) * 1000
* Plant Utilisation (%)
Energy Off-take (with Gen) = Energy Off-take (no Gen)
- Embedded Generation Output
Displaced System Energy =
Energy Off-take (no Gen) - Energy Off-take (with Gen)
This only looks at the delivered energy that is displaced. The cost of energy taken by
the transmission and distribution systems in terms of losses is accounted for within a
separate part of this calculation methodology.
52
It is noted here that the Market Arrangements for Electricity are presently under discussion prior to implementation in 2005. This envisages use of Locational Marginal Pricing for the wholesale market and
therefore any benefit calculation under the MAE will need to take this into consideration.
-117 -
Step
2
Name
Determine Displaced
System Plant
From
To
ESB
ESB
Networks
Networks
Description
Data
It is proposed that this is determined through consideration of the embedded
generation expected load factor as determined from the expected generation profile.
This load factor will then identify whether the embed generation is expected to
displace base load plant, mid merit plant or peaking plant.
The proposed categories of plant are detailed below:
•
Base Load >75%LF (BNE Pricing);
•
Mid Merit 30 to 75%LF (ESB PG Allowable revenue);
•
Peaking <30% LF (Oil plant price)
This selection will select the avoided energy price and the avoided fuel type (used for
calculation of emissions and fuel benefits in later sections).
3
Value of Displaced Energy
ESB
ESB
Networks
Networks
The Value of the Displaced Energy is calculated as follows:
Value of Displaced Energy
= Displaced System Energy (Step 1)* Displaced Energy Price (Step 2)
4
Cost of Generated Energy
ESB
ESB
Networks
Networks
The costs associated with the generation of the energy by the embedded generator
will need to be set off against the saving in system energy costs. The embedded
generation output will not be the same as the displaced system energy at the
transmission system exit point due to the impact of the embedded generation on the
distribution system losses. This is taken into account in the following equation:
Embedded Generation Output = Embedded Plant Capacity (MW) * 1000
* Plant Utilisation (%)
Cost of Energy Generated
= Embedded Generation Output * Embedded Generation Price
The price of the embedded generation output will be a commercially sensitive
-118 -
Forecast Plant Operation
Step
Name
From
To
Description
number and there will need to be sufficient assurances in place to address any issues
relating to confidentiality.
5
Net Energy Benefit
The Net Energy Benefit pa is the difference between the system generation cost and
the embedded generation cost in the first year of operation of the embedded
generation.
Net Energy Benefit pa = Value of Displaced Energy (Step 3)
- Cost of Energy Generated (Step 4)
This value will need to be projected forward.
15
•••Net Energy Benefit =• Σ(Net Energy Benefit pa / (1+DF)n )
n=1
-119 -
Data
6.8
Loss Benefit Calculation
The connection of embedded generation plant to a distribution network has a number of impacts for the day-to-day
operation of the system and also for the longer term planning and security of the distribution system. These impacts
can be localised to the generator or may have an effect further a field dependant on the size of the generator and
the capability of the distribution network at the point of connection for the generator.
This process considers the steps required to determine the impact of the embedded generator on the distribution
system losses. These losses arise in the form of heat in the system (predominantly load related) and in the form of
inefficient use of system capacity (kW) that increases the assets required to serve a given load. Embedded
generation can provide some off set of the energy losses and may release some of the capacity presently used by the
losses. Each of these elements has a value associated with them.
Power Losses – in general the connection of embedded generation plant will reduce the demand on the
upstream network at times of peak load whilst leaving the downstream network relatively unaffected, and
this will be seen as a benefit to all users through deferred / avoided system reinforcement leading to
reduced loos costs requiring recovery through the use of system charges.
Energy Losses – Although running embedded generation at times of peak load will reduce network power
losses at peak load, the reverse is true at times of light load where operation of embedded generation may
actually increase the losses if the generator is exporting power to the grid. Since peak load conditions only
exist for a short period during the day and the period of light load covers a much longer period when
electricity demand is low, the overall effect of running embedded generation throughout any 24-hour
period may actually be to increase the overall energy loss.
With the present commercial arrangements developers of embedded generation are encourage to
maximise their financial return by maximising their generating capacity and their “in-service” hours per
year. However, as noted above, this approach is likely to increase the energy losses of individual schemes,
which is in contrast with an energy saving policy. It is conceivable therefore that a time will come when
developers are encouraged to consider the need to minimise losses, since a reduction in energy losses
would be beneficial to the environment, with a resulting saving in the amount of fuel being used and
carbon dioxide emissions.
The cost of the losses needs to be assessed over a period that represents the expected life of the embedded
generation plant. Such a consideration should bring out a life cycle cost associated with the embedded generator
connection to the distribution system on the basis of the system conditions at the time of connection. The
calculations will be made on the basis of the existing distribution system and the presently accepted connection
offers as at the date of the calculation. It is recognised that the distribution system undergoes frequent change due
to new connections or de-commissioning connections that are no longer required. This does introduce a degree of
uncertainty into the calculation process. However, this calculation is concerned with the incremental impact of the
embedded generation on the system losses.
This process only considers the impact of the embedded generator on technical losses.
-120 -
6.8.1
Inputs
Distribution System data – electrical parameters, operating configuration;
Load Duration data – current load shape and quantities, forecast load growth
Forward Energy Prices at the Distribution :Transmission interface
Marginal Capacity Costs for the Distribution System.
Embedded Generation expected generation profile in terms of kW and kWh.
6.8.2
Outputs
Statement of the net losses Benefit arising from the connection of the generation plant to the ESB distribution
network.
6.8.3
Participants
ESB Networks
-121 -
Loss Benefit Calculation
5
5
With Generation
Existing Network
Network
Model
without
Generation
Network
Demand
Profile Yr1
9
Calculate
Network Peak
Loading
Network
Model with
Generation
System
Peak
Capacity
2
Calculate Peak
Loss Capacity
kW
Marginal
Capacity
Costs
System
Peak
Capacity
10
Calculate Peak
Loss Capacity
kW
Marginal
Capacity
Cost
3
Calculate Capacity
Loss Value
Generation
Profile
ESB Networks
Network
Demand
Profile Yr1
1
Calculate
Network Peak
Loading
Wholesale
Market
Prices
11
Calculate Capacity
Loss Value
4
Calculate Loss
Load Factors
12
Calculate Loss
Load Factors
5
Calculate
Energy Loss
kWh
13
Calculate
Energy Loss
kWh
6
DWA Energy Price
for Losses
7
Calculate Energy
Loss Value
Wholesale
Market
Prices
14
DWA Energy Price
for Losses
15
Calculate Energy
Loss Value
8
Project Loss
Value
-122 -
16
Project Loss
Value
17
Determine Net
Loss Benefit
6.8.4
Process Description:
Step
1
Name
Calculate Network Peak
Loading
From
To
ESB
ESB
Networks
Networks
Description
Taking the network model, ESB Networks will calculate the loading of each system
Data Sources
Network Demand Profile Yr 1
element within the distribution network model at peak times and derive the required
capacity at the transmission interface to service that peak demand.
2
Calculate Peak Loss
The difference between the kW capacity required at the network source and the
Capacity kW
demand kW served by the system. This difference is the system capacity required to
support the losses at system peak demand.
3
Calculate Capacity Loss
This will require knowledge of the cost to provide one kW of incremental system
Value
capacity.
Marginal Capacity Costs
The calculation is the simple product of the marginal Capacity Cost and the Peak Loss
Capacity amount.
4
Calculate Loss Load Factor
In order to determine the expected annual average energy loss on the network, the
load factor for the energy losses can be calculated on the basis of the following
equation:
Copper Loss LF = A*LF^2 + LF*(1-A) where A is 0.85
Fixed Loss LF = Demand Load Factor
LLF = Fixed LLF * (1-A) + Copper LLF * A
5
Calculate Energy Loss kWh
This Loss Load Factor can then be used to determine the approximate energy loss on
the system by multiplying the peak loss capacity by the Loss Load Factor and the
number of hours in the year (8760).
-123 -
Network Demand Profile Yr 1
Step
6
Name
From
To
Description
Data Sources
DWA Energy Price for
The Demand Weighted Average energy price would ideally be derived from market
Market Prices
Losses
prices and the forecast energy losses during each settlement period in the year.
Loss Load Factor
Peak Loss Capacity
x
x
DWA = ΣkWhn * MPn / Σ kWhn
n=1
n=1
Where:
x
= number of settlement periods in a year
KWhn = net system demand in each of the settlement periods in the year
MPn = market price during a settlement period
Recognising that the level of detail of information may not be readily available or
could be subject to interpretation, it is considered prudent to reference prices that
relate to system plant operating in a similar mode:•
Base Load >75%LF (BNE Pricing);
•
Mid Merit 30 to 75%LF (ESB PG Allowable revenue);
•
Peaking <30% LF (Oil plant price).
This may not provide the finest detail, however, it retains transparency in terms of
price derivation and gives simplicity to the calculation process – therefore reducing
the overhead required.
7
Calculate Value of Energy
This energy price may then be multiplied with the energy losses to derive the value of
Losses kWh
the system energy loss in the year
-124 -
Step
8
Name
Project Value of Losses
From
To
Description
Project the value of the losses on the basis of the network at this point in time over the
Data Sources
Financial Data
proposed time horizon – 15 years.
NPV = Sum of [ Loss Valuen / (1+DF)n ] for n = 1 to 15 where Loss Value is
constant.…….
9
Calculate Network Peak
Using the revised network model with generation developed in the LCTAS process,
Loading
ESB Networks will calculate the loading of each system element within the distribution
network model at peak times and derive the required kW capacity at the transmission
Generation Profile;
Network Demand Profile
Year 1
interface to provide that demand.
The system demand profile will need to be amended to take into account the
expected output from the generator at the peak time. This may entail incorporating a
Network Model with
Generation
‘diversity’ factor to represent the intermittency of the generation output (Wind) or to
factor in expected plant reliability.
10
Calculate Peak Loss
The difference between the kW capacity required at the transmission system interface
Capacity
at peak time and the demand kW served by the system. This difference is the system
capacity required to support the losses at system peak demand.
11
Calculate Capacity Loss
This will require knowledge of the cost to provide one kW of incremental system
Value
capacity.
The calculation is the simple product of the Marginal Capacity Cost and the Peak Loss
Capacity amount.
-125 -
Marginal Capacity Costs
Step
12
Name
Calculate Loss Load Factor
From
To
Description
In order to determine the expected annual average energy loss on the network, the
load factor for the energy losses can be calculated on the basis of the following
equation:
Copper Loss LF = A*LF^2 + LF*(1-A) where A is 0.85
Fixed Loss LF = Demand Load Factor
LLF = Fixed LLF * (1-A) + Copper LLF * A
13
Calculate Energy Loss
The Loss Load Factor can then be used to determine the approximate energy loss on
the system with the generation connected. This loss calculation needs to take into
account that the generation will not be available 100% of the year therefore the loss
benefit will not always be on the basis of the calculated peak benefit. To provide an
approximation it is assumed that when the generation plant is not operating the
average distribution energy loss occurs.
Energy Loss with Generation =
LLF * Peak Loss Capacity with Gen (kW) * Generator Availability * 8760
+ (1- Generator Availability) * Energy Loss without Generation
-126 -
Data Sources
Step
14
Name
From
To
Description
DWA Energy Price for
The Demand Weighted Average energy price would ideally be derived from market
Losses
prices and the loss load factor to give a price for the energy loss saved.
x
Data Sources
Loss Load Factor
x
DWA = ΣkWhn * MPn / Σ kWhn
n=1
n=1
Where:
x
= number of settlement periods in a year
KWhn = net system demand in each of the settlement periods in the year
MPn = market price during a settlement period
Recognising that the level of detail of information may not be readily available or
could be subject to interpretation, it is considered prudent to reference prices that
relate to system plant operating in a similar mode:•
Base Load >75%LF (BNE Pricing);
•
Mid Merit 30 to 75%LF (ESB PG Allowable revenue);
•
Peaking <30% LF (Oil plant price).
This may not provide the finest detail, however, it retains transparency in terms of
price derivation and gives simplicity to the calculation process – therefore reducing
the overhead required.
15
Calculate Energy Loss Value
This energy price may then be multiplied with the energy losses to derive the value of
the system energy loss in the year
16
Project Loss Value
Project the value of the losses on the basis of the network at this point in time. Time
horizon is assumed to be 15 years.
NPV = Sum of [ Loss Valuen / (1+DF)n ] for n = 1 to 15 where Loss Valuen is constant
across the projection period.
-127 -
Financial Data
Step
17
Name
From
To
Description
Calculate Annual
Compare the annual loss values for the existing network and the network with the
Differences
additional generation to derive a net projection of loss benefit on a year-by-year basis.
Loss Benefit = Existing Loss Value – New Loss Value
-128 -
Data Sources
6.9
Voltage Benefit Calculation
Embedded generation are typically located closer to the load than system generation plant. This provides an
opportunity for the embedded plant to offset some to the reactive power requirements at the distribution system
interface with the transmission system providing a number of benefits to the distribution system. Namely – deferred
capital expenditure on the reinforcement due to power factor improvement; savings on voltage control equipment
and reduced take of reactive energy.
Many embedded generation plant are capable of providing reactive power to support voltage on the distribution
network. Conceivably this capability could allow the embedded generator to participate in the ancillary services
provision market – although this will be dependant on its connection location within the distribution system. More
typically the generator will provide benefit local to its connection point in terms of improved quality of supply.
Embedded generation connection to the distribution network is expected to require a more active approach to
distribution system control and operation – a change that will require further investment in assets and development
of new skill sets within the DNOs. This will become more pressing as a greater number and capacity of embedded
plant are connected to the network.
At the level of an individual embedded generation connection it is difficult to determine the incremental impact
that the plant will have on the operational costs within the DNO. Rather any cost increases are expected to
become apparent as they increase with the increase in DG connections. On this premise the costs would then be
most appropriately recovered on a societal basis through the DUoS charging structure from all distribution
system users, given that all system users are receiving the resultant benefits from active management of the
network. As a consequence these items are not considered further within the scope of this calculation process.
The majority of ESB Networks system is characterised as typical rural networks, based on overhead distribution with
long radial MV feeders supplying power to remote loads in sparsely populated areas. Such network configurations
are very susceptible to poor voltage regulation under peak load conditions (ESB typically install booster transformers
on the longest feeders to enable voltage criteria to be met) with significant voltage drops being experienced
between the source substation and the remote end of the MV feeder. Connecting embedded generation to such
networks tends to improve the situation through provision of voltage support. Although the extent of any
improvement largely depends on where the generator is connected and its capacity. If the generator can provide
sufficient voltage support then the DNO may avoid the need to provide additional voltage support mechanisms.
However, such benefits to the DNO may come at a cost to the generator in terms of connection location, connection
costs and power factor restrictions on operation.
The calculation process within this section assumes that the generator is connected to a point on the network that
has sufficient short circuit capacity to allow generator switching operations whilst staying within the allowed limits
for step change in voltage – required to ensure compliance with the LCTAS connection design.
Voltage flicker is a consideration, however, it is difficult to quantify given that it is predominantly driven by
individuals’ perception at the point of use. Similarly waveform harmonics are not qualified within this calculation
process as the impact of these are accounted for within the connection costs and choice of point of connection
made in the LCTAS process.
-129 -
6.9.1
Inputs
Network Parameters; Reactive Power Costs; Embedded generation profile; Demand Load Profile; O&M Costs; Asset
Life Costs
6.9.2
Outputs
Net Voltage Benefit
6.9.3
Participants
ESB Networks
-130 -
Voltage Benefit
Existing Network
1
Calculate Reactive
Energy
2
Determine
Reactive Energy
Price
Network
Model
without
generation
ESB
Networks
DUoS
Tariffs
3
Calculate
Cost of kVArh
ESB Networks
4
Calculate
Voltage
Profiles
6
Plant
Generation
Profile
Network
Operation
5
Determine Cost
of voltage control
Demand
Load
Profile
O&M Costs
6
Calculate
Voltage
Profiles
7
Determine Cost
of Voltage control
8
Revised Future
Capital
Reinforcement
9
Determine
Deferred Capex
Value
10
Calculate Reactive
Energy
11
Calculate
Cost of kVArh
Network
Model
without
generation
ESB
Networks
DUoS
Tariffs
With Generation
-131 -
12
Determine
Reactive Energy
benefit
6
6.9.4
Process Description:
Step
1
Name
Calculate Reactive
Energy (kVArh)
From
To
Description
Data Sources
ESB
ESB
ESB Networks will calculate the total reactive energy to supply the demand and
Network Model without Generation
Networks
Networks
losses on the network. This calculation will use the total energy consumption on
Demand Load Profile
the network at the Distribution :Transmission interface and the annual average load
Annual Energy Demand
factor.
Annual Average Power Factor
Metering data (if available)
kVArh pa = Peak kVArh * System Demand Load Factor
This assumes constant power factor throughout the year.
Where specific integrated annual metering data is available for this interconnection
point this data will be used to obtain the reactive energy consumed by the network
during the year.
2
Determine Reactive
Energy Price
ESB
ESB
Networks
Networks
Pricing of reactive energy charged to DNO connected customers. This assumes that
the cost of the reactive energy is displaced at the point of use rather than at the
point of Distribution :Transmission interface. Therefore the pricing used is that
stated in the current ESB Networks UoS tariffs for reactive energy at the same
voltage level as the embedded generation connection.
3
Calculate Cost of kVArh
ESB
ESB
Networks
Networks
Using the annual reactive energy use and the reactive energy price calculate the
cost of the annual kVArh supplied.
kVArh Cost = kVArh Use * kVArh price
This provides a base-line for the cost of reactive energy for the distribution network.
4
Calculate Voltage
Profiles
ESB
ESB
The system voltage profile will vary with the demand and the operational decisions
Networks
Networks
made in respect of system configuration. These data will determine the necessary
control actions required or assets to be installed as part of the normal planning
process.
-132 -
ESB published DUoS tariffs
Step
5
Name
Determine Cost of
Voltage Control
From
To
Description
ESB
ESB
It may be possible to determine the impact of voltage control operations on the
Networks
Networks
overall asset operating lives and maintenance costs associated with the assets.
Data Sources
However, these costs will be incorporated within the analysis undertaken as part of
ESB Networks normal system planning process and therefore these costs will be
incorporated into the DUoS charges for cost recovery. They are not considered
further within this calculation.
6
Calculate Voltage
Profiles
ESB
ESB
Networks
Networks
The system voltage profile will vary with the demand and the operational decisions
made in respect of system configuration.
The LCTAS process of determining the required connection and reinforcement to
enable connection of the embedded generation will determine the impact on the
system voltage profiles.
7
Determine Cost of
Voltage Control
ESB
ESB
The additional costs of voltage control will be accounted for within the connection
Networks
Networks
offer (depending on whether a shallow or deep regime applies) and through DUoS
ESB
ESB
Networks
Networks
charging.
8
Calculate Revised
Future Capital
Reinforcement
To the extent that there is a deferral in the need to incur voltage driven system
reinforcement capital spend then there will be a benefit from the connection of the
embedded generation to the distribution network. The capital expenditure
associated with any voltage driven capital expenditure will need to be identified ,
the previously planned to be implemented date and the revised implementation
date.
-133 -
ESB Network Plan
Step
9
Name
Determine Deferred
Capex Value
From
To
ESB
ESB
Networks
Networks
Description
Data Sources
This calculation will derive the difference in the present value of the ‘before’ and
‘after’ voltage driven distribution system reinforcement.
Deferred Capex Value =
‘Before’ Capex Spend / (1 + DCF)^P1 –
‘After’ Capex Spend / (1+DCF)^P2
where:
DCF = discount factor
P1 = no. of years difference between present year and initial investment year;
P2 = no. of years difference between present year and the revised investment
year;
10
Calculate Reactive
Energy with Generation
ESB
ESB
Networks
Networks
ESB Networks will calculate the total reactive energy to supply the demand and
Generation Profile;
losses on the network with the generation operational. This calculation will use the
Demand Load Profile;
expected generation profile to determine the total energy consumption on the
network at the Distribution :Transmission interface and the annual average load
factor.
kVArh pa = Peak kVArh * System Demand Load Factor
This assumes constant power factor throughout the year.
Where specific integrated annual metering data is available for this interconnection
point this data will be used to obtain the reactive energy consumed by the network
during the year.
-134 -
Step
11
Name
Calculate Value of
kVArh Saved
From
To
ESB
ESB
Networks
Networks
Description
Using the annual reactive energy use and the reactive energy price calculate the
cost of the annual kVArh supplied.
kVArh Cost = kVArh Use * kVArh price
The kVArh price will be the value derived in Step 2.
Then this value is subtracted from the result from Step 3 to derive the reactive
energy benefit from the embedded generation operation in one year.
12
Determine Reactive
Energy Benefit
ESB
ESB
Networks
Networks
This is the sum of the deferred capex benefit (Step 9) and the Present Value of the
result in Step 11 (Value of kVArh Saved) over the 15-year projection period.
Reactive Energy Benefit = Deferred Capex Benefit +
15
Σ (Value of kVArh saved / (1+DF)n )
n=1
where Value of kVArh saved is constant across the period.
-135 -
Data Sources
6.10
CML Benefit
In the event of an incoming supply failure to an area of the distribution network in which generation is embedded,
protection equipment can be set to operate (on the basis of the rate of change of frequency) to “island” the
embedded generation and part of the affected network in order to ensure that at least part of the affected load
remains supplied. The obvious benefit of this “islanding” capability is that it reduces the amount of lost load. In
remote areas that suffer regular interruptions in supply, the savings in respect of lost load could be relatively high.
The economic savings are dependent on the Value of Lost Load (VoLL) and the outage duration. The Distribution
Network Operator (‘DNO’) will benefit from reductions in the number of Customer Minutes Lost (CMLs) and
Customer Interruptions (CI’s) that are used to measure supply availability on the allowed DUoS revenue, whilst the
customer will benefit from an improvement in the availability of supply.
To facilitate “islanding” of the network the DNO will be required to install more complex interface protection to
satisfy safety and supply quality criteria.. An additional cost that also has to be borne is for a secure communications
channel from the generator to the DNO’s control centre. It should be noted here that at the time of writing this
report, ESB Networks prohibits “islanding” generation with matched blocks of demand due to safety and supply
quality concerns. Therefore, whilst CML benefit maybe realisable, such benefit could be outweighed by the cost to
implement an islanding scheme that addresses these safety and quality concerns.
The overall CML benefit will be the net of the costs associated with the implementation and operation of any
“islanding” scheme for the embedded generation and the value attributable to any savings in the amount of lost
load (CML saved * VoLL) and additional cost recovery through additional DUoS charges that can be made to
customers. There may also be benefit derived by the DNO through cost savings from avoided penalties that could
be imposed in the event that they do not meet quality of supply / CML target levels in a given period – however,
these have not been included within the calculation.
6.10.1 Inputs
Islanding Scheme costs; Network Topography; Network Equipment Statistical data; Network Operational restoration
statistics; Customer Interruption statistics; Value of Lost Load; Financial Data
6.10.2 Outputs
Net CML Benefit
6.10.3 Participants
ESB Networks
-136 -
CML Benefit
6.10.4
7
1
Determine existing
system statistics
Fault
Statistics
5
Determine
expected system
statistics
6
Investigate
Islanding
Potential
ESB Networks
2
Calculate
expected CMLs
Generator
Parameters
Yes
9
Revised
restoration
scheme B
No
7
Revised
restoration
scheme A
3
Calculate Value of
lost kWh
Value of
Lost Load
4
Project Value of
Lost Load
Financial
Data
8
Design islanding
scheme
10
Calculate revised
CMLs
11
Calculate Value of
Lost kWh
12
Calculate
Additional
DUoS income
13
Project Values
16
Determine net
CML benefit
-137 -
7
6.10.4 Process Description:
Step
1
Name
From
To
Description
Data
Determine Existing
ESB
ESB
The calculation of the network section System Average Interruption Duration Index (SAIDI)
Network Topography
Network Statistics
Networks
Networks
and the System Average Interruption Frequency Index (SAIFI) values will need to be
Failure statistics
completed by ESB networks, to allow the determination of the expected CML’s on that
Network Fault statistics
network.
2
Calculate Expected CMLs
ESB
ESB
This will be the product of the number of customers served by the network section, the
Number of customers
Networks
Networks
network SAIDI and the network SAIFI. This will give the expected number of customer
supplied on network
minutes lost on that section of the network in a year.
segment;
CML pa = No of Customers * SAIDI *SAIFI
3
Calculate Value of Lost
kWh
ESB
ESB
Networks
Networks
The quantity of energy supplied per customer minute for the network is calculated,
multiplied by the number for customer minutes lost and then by the Value of Lost Load to
determine the value of the lost kWh.
Value of Lost Load;
Real Power Peak
Demand;
Demand Load Factor;
Energy / Customer Minute = (Peak Power Demand * Load Factor * 8760)
No. of customers * 60
Energy Lost due to faults = CML pa * Energy / Customer Minute
Value of Lost Energy =
Energy Lost due to Faults * Value of Lost Load
This calculation assumes that the fault incidence is random and that the customers affected
by faults over a year are equivalent to an ‘average’ customer connected to that network. If
-138 -
Step
Name
From
To
Description
Data
there are specific weaknesses in the distribution network that will effect a skew to the
incidence of faults towards a particular group of customers this will need to be recognised
in the calculation.
4
Project Value of Lost kWh
ESB
ESB
Networks
Networks
The annual value of the lost load is calculated to give a present value from a 15-year project
Financial Data
period
15
Σ (Value of Lost kWh / (1+DF)n )
n=1
The Value of Lost Load remains constant for each year of the project.
5
Determine Expected
System Statistics
ESB
ESB
Networks
Networks
Following the completion of the LCTAS connection design process the new equipment and
Fault Statistics;
any system reinforcement will have been identified. From the historic fault statistics for
these new equipment types - a revised expectation for SAIFI - SAIFIg - can be determined.
6
Investigate Islanding
Potential
ESB
ESB
Networks
Networks
Prior to any significant effort being expended on developing detailed islanding scheme
design, ESB should investigate the possibility for the generator to provide island support to
the network. This will need to take into consideration the type of renewable generator, its
electrical capabilities and expected generation profile. An intermittent generator is
unlikely to be regarded as suitable for an islanding scheme, however, biomass plant or
other ‘non-intermittent’ technologies may be seen to be suitable.
If the generation is suitable then move to Step 10 – Design Islanding Scheme
7
Revised Restoration
Scheme A
ESB
ESB
Networks
Networks
If the scheme is not regarded as being suitable to connect the generator as an islanding
scheme then ESB Networks will need to devise a revised restoration scheme for the
network. This revised restoration scheme will allow calculation of the revised average
system interruption duration (SAIDIa) that will be used in the calculation of the expected
CMLs with the generator connected (Step 10)
-139 -
Output from LCTAS
Step
Name
From
To
8
Design Islanding Scheme
ESB
ESB
Networks
Networks
Description
Data
If the scheme is regarded as being suitable to connect the generator in island mode then
ESB Networks will need to design a generator islanding scheme in order to control the load
allocated to the generator and also to ensure that additional protection (egg RoCoF) is
installed and that the ESB operational control centre is able to control the generator to
allow re-synchronisation of the islanded network following clearance / restoration of the
faulted network.
The cost of implementing such an islanding scheme will be used to offset any benefit
arising from reduced CMLs.
9
Revised Restoration
ESB Networks will need to devise a revised restoration scheme for the network to take into
Scheme B
account the islanding capability of the generator. This revised restoration scheme will
allow calculation of the revised average system interruption duration (SAIDIb) that will be
used in the calculation of the expected CMLs with the generator having island mode
capability.
10
Calculate the revised
ESB Networks will need to recalculate their projection of the CMLs for the network with the
CMLs
generation connected using either restoration scheme A or Restoration Scheme B.
Revised CMLs = No of Customers * SAIDI * SAIFIg
Where:
SAIDI = SAIDIa when there is no islanding or SAIDIb when an islanding scheme is
implemented
No. of customers = Difference between the total number of customers on the
network and those within the islanding scheme. As those within the islanding
scheme are assumed to have no interruption in a year. Therefore the CML
calculation will only apply to those customers connected outside the islanding
scheme.
-140 -
Generation Profile
Step
11
Name
From
To
Description
Calculate the Value of
The quantity of energy supplied per customer minute for the network is calculated,
Lost kWh
multiplied by the number for customer minutes lost and then by the Value of Lost Load to
determine the value of the lost kWh.
The calculation will be slightly different depending on whether the islanding scheme is
implemented or not. If it is then the amount of energy lost will be reduced due to the
additional energy supplied to the customers in the affected area. This assumes that the
islanding scheme provides support to customer demand able to be supplied by the
generation capacity (i.e. effective use is made of the generator output)
Energy Lost due to faults = CML * Energy / Customer Minute
Value of Lost Energy = Energy Lost due to Faults * Value of Lost Load
-141 -
Data
Value of Lost Load
Step
12
Name
From
To
Description
Calculate Additional
To the extent that the embedded generation is able to provide energy to customers within
DUoS income
the curtelage of the islanding scheme during times of system faults, there will be additional
revenue for the DNO from DUoS charges that would otherwise have been forgone.
The value of the DUoS charges has been assumed to be that levied on customers with a
connection voltage similar to the embedded generator.
Additional DUoS income = (Existing Lost Load – Revised Lost Load) * DUoS
Where:
Existing Lost Load = output from Step 3
Revised Lost Load = result of the Energy Lost due to faults calculation in Step 11
13
Project Values of annual
benefits
15
Value of Benefit = Σ (Additional DUoS Incomen / (1+DF)n)
n=1
+ Value of Lost kWh (existing)
– Value of Lost kWh (with Generation)
14
Net CML Benefit
Net CML Benefit = Value of Benefit – Cost of Islanding Scheme
-142 -
Data
6.11
Asset Benefit
The connection of embedded generation to the distribution network introduces a new source of power on to the
network, that in many cases is located much closer to the demand than the existing power source, i.e. the local bulk
supply point. Consequently when the generation is in service delivering power to the network it will affect the
power flow between the existing source and the generator, and between the generator and the local customers. Of
course the extent to which the power flow is affected will depend largely in the magnitude of the connected
generation, the configuration of the network and the location of the generation itself.
In general the effect of the embedded generation will be to reduce power flows on the distribution network when
the generation is in service, although where the generation is teed into the existing network the power flow in the
network in the vicinity of the generator connection may well be increased.
In cases where the change in power flow on the local network in which the generation is embedded is significant,
and the output from the generation is considered a secure and reliable supply, then the embedded generation can
have a positive impact as far as the DNO reinforcement of the network in a particular area.
Embedded generation within a sector of the distribution network may contribute to the security of supply within
that sector, although this depends on the nature of the generation – wind for example provides little or no
contribution to system security unless available in substantial quantities when aggregation can provide some
contribution. In cases where the generation contributes to the security of supply of that distribution sector, the DNO
can subtract the corresponding load from the capacity of the connection it requires to the transmission system.
Over the longer term the reduced load may make it possible to avoid reinforcing or upgrading this connection and
thus reduce costs through avoided capital expenditure.
In a similar way embedded generation on the distribution network will reduce power flow down through the
transmission network to the local area bulk supply point. This can also allow the TSO to delay transmission system
reinforcement, particularly at the local bulk supply point. In the longer term, the overall concentration from a much
higher concentration of embedded generation on the network will be to reduce the power that would be
transported across the transmission system to well below the level that would be obtained if Ireland were to
continue with its reliance on conventional power stations connected to the transmission system. The load-related
capital expenditure budget of the TSO under this “embedded generation” scenario will then be significantly lower
than the budget for the alternative scenario in which embedded generation continues to play a minor part.
Although the effect of embedded generation on system reinforcement is seen as a reinforcement is seen as a real
benefit, in that it can allow network reinforcement to be delayed or avoided altogether, there may be an ‘upfront’
cost to the DNO and the Developer. This is the cost associated with strengthening the local network, near to where
the generator is connected, to allow the generation to deliver its contracted power to the network without any
constraints. This is typically the cost reflected in the connection offer made by ESB Networks to a Developer for
connection to the ESB Network.
-143 -
6.11.1 I nputs
Network Demand Profile; Forecast Load Growth; Forecast Generation Profile; Asset Replacement Costs
6.11.2 Outputs
Asset Benefit
6.11.3 Participants
ESB NG; ESB Networks
-144 -
Asset Benefit
8
Demand
Profile or
Meter Data
1
Determine Asset
Peak loading
without Gen
5
Determine Peak
Loading with
Generation
Network
Model
Forecast
Generation
Profile
ESB Networks
ESB Capital
Plan
2
Determine asset
replacement date
3
Peak Loss
Capacity Without
Gen
Forecast
Load
Growth
6
Revised Asset
replacement date
4
Peak Demand
Capacity Without
Gen
Capital
Expenditure
Plans
8
Peak Loss
Capacity With Gen
ESB TUoS
Charges
9
Peak Demand
Capacity Without
Gen
7
Calculate
Deferred
Capital
10
Embedded
Generation
Reliability
11
Displaced
Load
12
Value of Displaced
Load
13
Net Asset
Benefit
8
-145 -
6.11.4
Process Description:
Step
Name
1
Determine Asset Peak
Loading without
From
To
Description
Data
ESB
ESB
On the basis of the network without the generator connection, the peak loading will
Network Demand Profile
Networks
Networks
be calculated for the present demand profile. It is likely that there will be meter data
Network Parameters
for the distribution network off take at the transmission boundary – in which case the
Generator
annual coincident reactive and real power peak readings should be used.
2
Determine Asset
Replacement Date
ESB
ESB
Networks
Networks
The asset replacement date will be determined utilising the present asset
Forecast Load Growth
replacement policy, asset age, peak loading and expected load growth. There will be
ESB Networks Capital plan
reinforcement plans in place for the network as part of the ESB Network capital plan.
It is the cost and implementation date for these investments in the distribution
network that are required.
3
Peak Loss Capacity
ESB
ESB
without generation
Networks
Networks
The calculated values of the kW and kVAr capacity requirements of the network to
support the supply of electricity to the connected customers. This is for the existing
network without the generator connected.
4
Peak Demand Capacity
without Generation
ESB
ESB
Networks
Networks
This is the arithmetic difference between the system peak kW and kVAr capacity
requirements and the peak loss kW and kVAr capacity requirements. This gives the
proportion of the peak kW and kVAr capacities that serve the demand.
5
Determine Asset Peak
Loading with Generation
6
Revised Asset
Replacement Date
ESB
ESB
Networks
Networks
ESB
ESB
Networks
Networks
Using the network model with the generation connection and generator included the
Network Model with
network peak loading in terms of real and reactive power can be calculated. This is
Generation
network modelling process is not specified in any more detail within this study as it is
Demand Load Profile
a normal part of the ESB system capital planning activity.
Generation Output Profile
As a result of the connection of the embedded generation there may be a deferral in
Forecast Load Growth
the need to reinforce the distribution network. Such a capital expenditure deferral
ESB Capital Plan
may arise due to additional capacity being made available through the addition of the
assets required to connect the embedded generator. The output of this assessment
will be a value for capital expenditure and the expected implementation date(s). All
capital expenditure should relate to the network segment that the embedded
generation is connected to.
-146 -
Step
Name
7
Calculate Deferred Capital
From
To
Description
ESB
ESB
The deferred capital expenditure will be determined by comparison of the ESB capital
Capital Expenditure Plans
Networks
Networks
expenditure requirement for the network before the generation connection and the
before and after connection
capital plan after the generation has been connected. This comparison will be the
of the embedded generation
difference in the present values of the two capital expenditure profiles. These capital
plant
plans may incorporate a number of discrete investments at different points in time.
The calculation of the capital plan present value in each scenario is set out below:
15
Capital Plan PV (No Gen) •Σ (Capital Investmentn / (1+DF)n )
n=1
15
Capital Plan PV (Gen) •Σ (Capital Investmentn / (1+DF)n )
n=1
Deferred Capital Benefit =
Capital Plan PV (No Gen) - Capital Plan PV (Gen)
It is the difference between the two calculated present values that gives the deferred
capital benefit. NOTE if there is no benefit as a result of the generation being
connected to the DNO network the Deferred Capital Benefit = 0.
8
System Peak Loss Capacity
The embedded generation will impact on the system losses (either through
with Generation
increasing them or decreasing them) – either way this will impact on the proportion
of the required system peak capacity to service the system peak demand. The
financial cost of this loss impact is accounted for within the Loss Benefit calculation
and therefore is not included within the calculation of ‘Displaced Load’ other than to
determine the capacity released to service additional demand.
9
System Peak Demand
The proportion of the peak system capacity that is solely attributable to the provision
Capacity Requirement
of electricity to the connected customer demand – this is exclusive of system capacity
-147 -
Data
Step
Name
From
To
with Generation
Description
required for losses.
Peak Demand Capacity requirement (kW) =
Network Peak Loading with Generation (kW) (Step 3)
* Peak Loss Capacity with Generation (kW) (Step 4)
Peak Demand Capacity requirement (kVAr) =
Network Peak Loading with Generation (kVAr) (Step 3)
10
Embedded Generation
Reliability
ESB
ESB
Networks
Networks
Peak Loss Capacity with Generation (kVAr) (Step 4)
The reliability of the embedded generation will need to be assessed. This is typically
based on the technology and fuel used by the generator with intermittent fuel
sources reducing the generation reliability from a distribution system perspective.
For the purposes of the example calculations the following values for embedded
generation reliability have been used:
CHP
= 85%
Peat
= 85%
Biomass = 70%
11
Displaced Load
Hydro
= 35%
Wind
= 25%
ESB
ESB
The amount of capacity that can be released for use by other customers or released
Networks
Networks
back to the transmission network at the exit point is determined by the reliability of
the generator and the difference between the peak demand capacity with and
without the generation.
Displaced Load = Generation Reliability *
(Peak Demand Capacity (no Gen) (kW) from Step 4
-148 -
Data
Step
Name
From
To
Description
Data
- Peak Demand Capacity (with Gen) (kW) from Step 9)
12
Value of Displaced Load
The value of the displaced load to ESB Networks is to the extent that they do not need
ESB National Grid TUoS
to pay for the TUoS exit charge related to the avoided capacity.
charges
Value of Displaced Load
= Demand Network Capacity Charge * Displaced Load
13
Determine Asset Benefit
ESB
ESB
Networks
Networks
A positive benefit arise when the costs of asset replacement under the no generation
scenario are greater than the asset replacement cost under the with generation
scenario. (Note: the cost of any asset replacement due to reinforcement activity
related to the initial connection of the generator to the distribution system are
accounted for outside this calculation through a deduction of the initial connection
costs from the overall net benefits).
Also the Displaced Load contribution to this benefit will need to be projected forward.
It is recognised that the DNO may elect to not forgo transmission system exit capacity
due to the uncertainties over load growth (i.e. it can be “chunky”) or from concerns
that the capacity, once released may be taken up by another party – therefore
potentially increasing the DNO’s future capacity costs. Irrespective there is an
opportunity to reduce the transmission system exit capacity and a benefit associated
with that in terms of avoided connection charges for the DNO.
Asset Benefit = Deferred Capital Benefit
15
+ Σ (Value of Displaced Loadn / (1+DF)n )
n=1
-149 -
6.12
Transmission Benefits
The connection of embedded generation within the distribution system has a number of associated costs and
benefits. Typically these have the greatest and most immediate impact on the distribution system to which they are
connected. However, given the interconnected and real time nature of electricity networks the impacts of the
embedded generation connection are not limited to the distribution system. The extent of the effect that
embedded generation plant has on the transmission system at, and beyond the relevant transmission system exit
point, is dependant on the size and electrical proximity of the embedded generation to the transmission system exit
point.
The impacts that will be seen on the transmission system will parallel those seen on the distribution network.
Including potential deferred capital expenditure, change in system losses and impact on the quality of supply that
will impact the requirement for system ancillary service provision. This process within the calculation methodology
allows the quantification of the impact of the embedded generation on the transmission system.
The impact of the displaced energy on the transmission system is accounted for within a separate part of the
calculation methodology.
It is noted that the Market Arrangements for Electricity scheduled for introduction in 2005 will introduce locational
marginal pricing (LMP) for each transmission entry / exit point. These LMPs will incorporate the cost of constraints,
losses etc in sending a signal to the market in order that investment is made at the most appropriate places on the
transmission system. In this case the loss and ancillary service cost / benefit calculation will only need look at any
differential in the ‘before’ and ‘after’ LMP for the exit point to determine the impact o the embedded generation.
6.12.1 Inputs:
Transmission System Losses; Ancillary Service Contracts; System Operational Standards; Distribution Network Offtake capacity requirements
3.12.2 Outputs:
Net Transmission System Benefit
6.12.3 Participants:
ESB NG
-150 -
Transmission Benefits
5
TUoS Charges
without Gen
Exit Point
Energy
Demand no
Gen
4
Transmission
Energy Loss
without Gen
ESB NG
9
12
TUoS Charges
with Gen
ESB TUoS
Charges
Exit Point
Energy
Demand
with Gen
10
Transmission
Energy Loss
with Gen
1
Exit Capacity
without
Generation
6
Exit Capacity with
Generation
Network
Model
without
Generation
Network
Model with
Generation
2
Asset
Replacement
without Gen
8
Asset
Replacement
with Gen
ESB Capital
Plan
Revised
Capital Plan
3
Ancillary Service
Costs without
Generation
9
Ancillary Service
Costs
with Gen
-151 -
11
Transmission Loss
Benefit
7
Exit Capacity
Saving
13
Net Transmission
Benefit
9
6.12.4 Process Description:
Step
1
Name
Exit Capacity without
From
To
Description
ESB NG
ESB NG
This is the amount of exit capacity required to service the distribution system demand and
Exit Point Meter Data;
losses at the relevant transmission exit point at peak times. This is determined by ESB
ESB Networks system model
Generation
Data
Networks through modelling of the customer demands, however, where metered data is
available at the transmission exit point this would be a preferable data source.
2
Asset Replacement
ESB NG
ESB NG
The requirement to replace transmission assets will be determined as part of the ESB NG
capital planning process and should be identified within the capital expenditure budget for
the business. The date and value of the transmission system capital spend related to the
relevant transmission system exit point need to be identified.
3
Ancillary Service Costs
ESB NG
ESB NG
Without DG
ESB National Grid may able to identify the cost of ancillary service arising from a particular
transmission exit / entry point. In order to determine the ancillary service costs would
require modelling of the Irish network in each settlement period on the basis of a number
of generation dispatch scenarios.
This has not been undertaken within this study.
4
Transmission Losses
without DG
ESB NG
ESB NG
This will require the annual average system loss (%), the energy off-take at the exit point
(kWh) and the per unit cost of energy.
Cost of Transmission Losses (Before) = Annual Average System Loss
* Annual Energy Supplied at Exit Point * Energy Price
-152 -
ESB NG Capital Plan
Step
5
Name
TUoS Charges without
From
To
Description
ESB NG
ESB NG
This is the value of the annual TUoS charges payable by ESB Networks to supply the annual
Generation
energy demand at the transmission exit point that the embedded generation is connected
to. This includes the Demand Network Transfer Charge and the Demand System Service
charges.
The Demand Network Capacity Charge is not include within this part of the methodology
since it is used to determine the value of the Displaced Load under the Asset Benefit
calculation process and would be double counting if it was included here.
TUoS charges (no Gen) = Demand Supplied (no Gen) (MWh)
* (Demand Network Transfer Charge + Demand System Service Charge)
6
Exit Capacity with DG
ESB
ESB NG
Networks
This is the amount of exit capacity required to service the distribution system demand at
the relevant transmission exit point at peak times taking into account the expected
generation output profile and any increase / decrease in the distribution system losses.
7
Exit Capacity Saving
ESB
ESB
The difference between the ‘before’ and ‘after’ capacity required at the exit system
Networks
Networks
boundary. However, the actual capacity saving will be equivalent to the quantity of
displaced load. Therefore the exit capacity saving has been accounted for within the Asset
Benefit calculation and recognising it again here would lead to double counting of the
benefit.
Further, the net impact of ESB Networks reducing the exit point capacity will lead to
reduced revenue recovery for ESB NG, which over the longer term will be clawed back
through higher TUoS charges for all customers.
8
Asset Replacement with
DG
ESB NG
ESB NG
The requirement to replace transmission assets may need to undergo re-planning due to
the connection of the embedded generation and the delaying effect that it has on the load
growth seen at the transmission exit point. To the extent that some capital expenditure
items relating to the exit point can be delayed or even cancelled, there a benefit will
accrue.
-153 -
Data
ESB NG TUoS charges
Step
Name
From
To
Description
Deferred Capital Expenditure Benefit =
15
Σ ((Capital Investment (Before)n - Capital Investment (After)n)/ (1+DF)n )
n=1
9
Ancillary Services Costs
10
Transmission Loss with
ESB NG
ESB NG
As noted in Step 3 above this has not been included within this study.
with DG
ESB NG
ESB NG
DG
This will require the annual average system loss (%), the energy off-take at the exit point
(kWh) and the per unit cost of energy.
Cost of Transmission Losses (After) = Annual Average System Loss
* Annual Energy Supplied at Exit Point * Energy Price
11
Transmission Loss Benefit
ESB NG
ESB NG
The Transmission Loss Benefit is the difference in the annual cost of losses associated with
the provision of the energy demand (including distribution system loses) at the
transmission exit point.
Transmission Loss Benefit = Cost of Transmission Losses (Before)
– Cost of Transmission Losses (After)
12
TUoS charges With
Generation
ESB NG
ESB NG
As in Step 5 above the Demand Network Capacity Charge is not included in this calculation.
The revised annual energy off-take from the transmission system is used for this
calculation.
TUoS Charges with Gen = Energy Off-take with Generation (MWh) * (Demand Network
Transfer Charge + Demand System Services Charge)
Net TUoS Benefit = TUoS Charges (no Gen) – TUoS Charges with Gen.
-154 -
Data
Step
Name
From
To
13
Transmission Net Benefit
ESB NG
ESB NG
Description
This is the sum of all of the individual calculated elements:
Transmission Net Benefit = Deferred Capital Expenditure Benefit
15
+ Σ ((Transmission Loss Benefitn + Ancillary Service Benefitn) / (1+DF)n )
n=1
15
+ Σ (Net TUoS Benefitn / (1+DF)n )
n=1
-155 -
Data
6.13
Emissions Benefit
The use of renewable fuels for embedded generation will reduce greenhouse gas emissions and particulates. The
level of reduction actually achieved will depend on factors such as:
The fossil fuel fired generation that is replaced or is avoided. For example, the replacement of existing coal fired
plant by renewable generation would give a greater emissions reduction than if it is used to avoid gas-fired plant;
The strategy adopted to manage wind power variability. For example, operating thermal plants at part load to
increase responsiveness will reduce their efficiency, resulting in lower emissions reductions per unit of wind energy
generated;
The specific mix of embedded generation technologies adopted, remembering that not all embedded generation is
renewable
Further benefit may be derived from avoided carbon trading costs under the auspices of the EU ETS. The total
number of allowances must be consistent with each states Kyoto commitments but the allowance distribution is
determined by national governments under the principle of subsidiarity. A reduction in generation emissions
through an increase in embedded [renewable] generation could therefore make more allowances available for other
Irish industries. This would reduce the number that would need to be purchased from other member states, or even
provide income from sales of surplus allowances.
This process will calculate the cost of the emissions using the expected embedded generation profile to determine
the type of system power plant that has been displaced. It is recognised that additional incremental emissions are
likely to be caused due to the increased need for frequency response capability from the system plant to cover those
occasions where the embedded generation is not producing. It is considered that the cost overhead in undertaking
detailed system dispatch simulations for each embedded generation connection application would not be an
efficient use of resources and as such have proposed this relatively rough assessment calculation.
6.13.1
Inputs
System Generation Emission data; Embedded Generator Emission Data; Emission Costs; EU ETS Requirements;
System Plant Incremental Change Data
6.13.2 Outputs
Net Emission Benefit
6.13.3 Participants
ESB NG; ESB Networks
-156 -
Emissions Benefit
Emission costs will be
associated with CO2, SOx
NOx and particulate
emissions
10
1
Determine
Avoided System
Plant Type
2
Avoided System
Plant Emissions
3
Embedded
Generator
Emissions
System
Gen
Emission
Data
Gen plant
emission
data
Emission
costs
4
Net Emission
Savings
EU ETS
requirement
-157 -
6
Contribution to
National target
5
Value of emission
savings
10
6.13.4
Process Description:
Step
Name
From
To
1
Determine Avoided Plant
ESB
ESB
It is proposed that this is determined through consideration of the embedded generation
Networks
Networks
expected load factor as determined from the expected generation profile. This load factor
Type
Description
Data
Generation Load Profile
will then identify whether the embedded generation is expected to displace base load
plant, mid merit plant or peaking plant.
The proposed categories of plant are detailed below:
•
Base Load >75%LF
•
Mid Merit 30 to 75%LF;
•
Peaking <30% LF
This selection of will determine the per unit gaseous emissions from this type of system
plant.
2
Avoided System Plant
Emissions
ESB
ESB
Networks
Networks
The avoided system plant emissions can be calculated from the difference in the energy
System Plant Per Unit
supplied at the transmission system exit point that the embedded generation is to be
Emissions (g/kWh)
connected to. The energy supplied at the exit point takes into account any saving or
increase in the distribution system losses arising from the embedded generation
connection.
Energy saved = Exit Point Demand (Before) – Exit Point Demand (After)
Emissions Avoided (Tonnes pa)
= Energy Saved * System Plant Per Unit Emissions
10^6
Where this calculation is repeated for each of the following pollutants – CO2, NOx and SOx
-158 -
Step
3
Name
Embedded Generator
Emissions
From
To
ESB
ESB
Networks
Networks
Description
The emissions from the embedded generator will need to be calculated in order to
determine the pollutants released by its operation. This will use the per unit emission
values for the specific technology. Where possible data for the annual emissions for the
specific embedded generation plant may be available as part of the environment consent
application for the plant. For the purpose of this calculation methodology we have
assumed that the emissions are typical for a specific technology.
Embedded Generation Emissions (Tonnes pa)
= EG Output (kWh pa) * EG Per Unit Emissions (g/kWh)
10^6
where this calculation is repeated for each of the pollutants CO2, NOx an SOx
4
Net Emissions Savings
ESB
ESB
Networks
Networks
This is the difference between the avoided emissions through system plant being
displaced and the emissions produced by the embedded generator.
Net Emissions Savings (Tonnes pa)
= Emissions Avoided – Embedded Generation Emissions.
This will need to be repeated for each of the pollutants CO2, NOx and SOx.
5
Value of Emissions Saved
A monetary value per tonne will need to be determined for each of the pollutants. For the
purposes of this methodology we have used the following prices:
CO2 = market price reported value of carbon trade value =Euro 15 / T
NOx and SOx are not explicitly priced or able to be traded. Any value of avoided Sulphur
will be captured in the avoided energy price and energy losses calculations to system
power plant operators factoring the compliance cost into their marginal cost of generation
calculation.
Value of Emissions = Emission Price * Emissions Saved
••
-159 -
Data
Step
Name
From
To
Description
PV of Emissions Saved
15
= Σ (CO2 Valuen + SOx Valuen + NOx Valuen) / (1+DF)n )
n=1
6
Contribution to National
The EU ETS requires individual member states to achieve specific targets. There are no
Target
financial penalties that apply to the states for any non-compliance with emissions targets,
however, there is value in reporting this as a non-fiscal quantitative measure to assist in
tracking the impact of renewable generation on the states achievement of target.
-160 -
Data
6.14
Social Benefit
The Social benefit that may arise through the connection of the embedded generation may be seen through a
number of different areas. Whilst the social impact of renewable plant can, theoretically be projected to include
such social benefits as reduced hospital care cost due to reduced pollutants and wider economic benefits that arise
from any such improvement in the general health of the population, these are not considered within the calculation
methodology proposed within this study. Though it is recognised that a cumulative impact of many renewable
generation projects within a country is likely to have a positive effect on health.
More immediately felt benefits will arise through the creation of local employment, wither in the provision of an
indigenous fuel source in the case of biomass plant, through short-term employment during the construction phase
of the project and potentially longer-term employment through the potential need for maintenance and operational
staff for the larger projects.
6.14.1 Inputs
Number of Jobs; Value of Jobs
6.14.2 Outputs
Social Benefit
6.14.3 Participants
ESB Networks
-161 -
Applicant
Social Benefit
Need to ensure that the fuel
income is not already
included within the job
creation benefit.
Fuel
source data
(volume &
cost)
Local rent
payments
ESB NG
Generator
Capacity &
Type
4
Calculate any
resulting income
losses
11
ESB Networks
Annual
energy
output
1
Calculate local
jobs created
2
Calculate local
income from jobs
Job
creation per
MW
database
Value of
jobs
-162 -
3
Calculate total
local income
5
Calculate
geographical and
net benefits
11
6.14.4
Process Description:
Step
Name
1
From
To
Description
Calculate Local Jobs
Dependent on the size of the generation project and its complexity. The larger wind farms are
Created
likely to require a manned control point – at least during office or extended office hours.
Data
Generator Size
Generator Type
The construction period and construction techniques required will also allow an estimate to be
made of the number of jobs that will be created during the construction period.
2
Calculate Local Income
The type of jobs created will allow the work to be valued in terms of likely annual income for
from Jobs
these jobs.
Value of Jobs
Local Income from Jobs = No of Jobs * Job Value
3
Calculate total Local
This will include other local benefits to the extent that rental income is paid for access and
Project Rental
income
occupation of land by the project. This assumes that such rental payments are made and stay
Payments
within the local community.
Also there will be issues related to the confidentiality of the commercial arrangements entered
into between the project developer and the landowner. As such the value of any rental income
may need to be assessed on the basis of standard valuation for the land.
Total Local Income =
Local Income from Jobs + Rental Value
-163 -
Step
4
Name
From
To
Description
Calculate any Resulting
The benefits that accrued locally will be offset to some extent in the event that the displaced
income losses
energy causes cash flow issues for any system plant. To the extent that this happens there will
be an offsetting ‘disbenefit’ due to loss of employment at such system plant. This is considered
to be a wider economic issue and not easily quantifiable for the purposes of a single embedded
generator. However, as the capacity of embedded generation grows the combined impact on
the viability of the system power plant is likely to become visible.
5
Calculate Geographical
Social Benefit = Total Local Income – Employment Costs at System Pant
and Net Benefits
-164 -
Data
6.15
Fuel Benefit
Any fuel benefit will arise through avoided use of imported fuels in favour of indigenous fuels. This is explicit in the
case of renewable energy systems, however, it is less clear for CHP plant given that they tend to be fuelled with
natural gas. However, there will be a displacement benefit arising from CHP plant due to their overall higher thermal
efficiency in terms of the ratio of fuel energy in to the useful energy produced (both electricity and heat). Therefore
in the case of CHP plant the cycle conversion efficiency needs to be used in the calculation of any fuel benefit.
6.15.1
Inputs
Displaced System Data; Embedded Generation Data; Energy Prices
6.15.2
Outputs
Displaced Fuel Benefit
6.15.3
Participants
To be determined
-165 -
Fuel Benefit
12
1
Displaced Fuel at
System Level
2
Embedded
Generation Fuel
Use
3
Net Fuel Use
Benefit
Displaced
System
Plant Data
Embedded
Plant Data
Fuel Price
Data
-166 -
12
6.15.4
Step
1
Process Description:
Name
From
To
Description
Displaced Fuel at
The quantity of fuel that will be displaced at the system level will be equivalent to the
System Level
difference in the exit point energy demands before and after the connection of the
Data
System Plant Data
embedded generation.
The type of system plant that will be displaced is dependent on the expected operating
profile of the embedded generation and was the case for the calculation of Emission Benefit
and Displaced Energy Benefit the operating profile (load factor) of the embedded
generation plant is used to determine the displaced system plant. This provides the
required information on the displaced fuel type, plant efficiency and fuel pricing required for
this calculation.
Displaced Fuel at System Level =
Displaced Energy
System Plant Efficiency
It is assumed in this calculation that the energy required to support the transmission system
losses incurred in delivering the energy from the system generation to the exit point remain
constant for the purpose of this element of the calculation methodology.
2
Embedded
Generation Fuel Use
The fuel use of the embedded generation will be zero for all renewable generation projects –
including biomass (provided that this is grown indigenous to Ireland). However, where CHP
is concerned there is likely to be a requirement for natural gas and so the displaced system
energy will be replaced with a lower amount of gas use – i.e. an incremental benefit.
-167 -
Embedded Plant Data
Step
Name
From
To
Description
Data
The actual embedded generation output is likely to differ from the displaced system energy
at the transmission exit point due to the impact that the embedded generation has on the
distribution system losses.
Embedded Generation Fuel Use= Embedded Generation Output
Embedded Generation Efficiency
It is recognised that CHP plant will be replacing fuel previously burnt directly in boiler plant
for process heat production, and as a consequence we propose that the total cycle efficiency
be used in this comparison in order to capture the efficiency benefit in terms of avoided fuel
use.
3
Net Fuel Use Benefit
The Net Fuel Use Benefit is the difference between the input fuel energy required by the
system plant to provide the displaced system energy and the embedded generation plant in
displacing this system energy. The value is derived using a reference fuel price – likely to be
based on market price for imported energy (gas, oil, coal etc)
Net Fuel Benefit = Displaced Fuel Price *
(Displaced Fuel at System Level - Embedded Generation Fuel Use)
NOTE: The actual fuel cost for generation will vary from time to time as market prices
fluctuate. In order to facilitate this calculation it may be necessary to identify appropriate
price reporting statistics that reflect energy input pricing for generation in Ireland.
-168 -
Energy Prices
6.16
Example Calculations
In order to assess the impact of the constituent elements within the calculation methodology a spreadsheet has
been created (soft copy provided with the final report in CD form) to allow calculation of the benefit values using
assumptions and data results from the representative network modelling exercise. The detailed printouts from the
spreadsheet model are included within Appendix D. A number of example calculations have been carried out to
assess the difference between embedded generation technology types (i.e. “reliable” and “unreliable”) and between
locations on the network. Therefore the following were used as the basis for the example cost and benefit
calculations:• Generator Size
2.5MWe
• Generator Type
CHP (natural gas fired) and Wind Generation
• System Connection Points
• Mid 38kV Trunk
• Remote end of 38kV Trunk
• Remote end of Mid 38kV Trunk Spur
• Remote end of 5km 38kV Dedicated feeder
Technology
No Gen
Location
-
Wind Generation
Mid Trunk
End Mid Trunk
Spur
End Trunk
5km 38kV
Feeder
Cost / Benefit
Connection Cost
0
Displaced Energy
Loss Benefit
Voltage Benefit
53
-€ 250,000
-€ 250,000
-€ 250,000
-€ 250,000
0
€ 721,692
€ 721,692
€ 721,692
€ 721,692
0
€ 1,182,415
€ 169,869
€ 213,015
€ 23,776
0
€ 682,083
€ 82,868
€ 167,960
€ 459,534
CML Benefit
0
€ 17,637
€ 17,637
€ 17,637
€ 17,637
Asset Benefit
0
€ 858,847
€ 447,274
€ 452,969
€ 86,692
Transmission Benefit
0
€ 640,212
€ 640,212
€ 640,212
€ 640,212
Emission benefit
0
€ 885,713
€ 885,713
€ 885,713
€ 885,713
Social Benefit
0
€ 203,288
€ 203,288
€ 203,288
€ 203,288
Combined Benefit
0
€ 4,941,887
€ 2,918,553
€ 3,052,487
€ 2,788,545
Fuel Benefit (kWh pa)
0
21,900,000
21,900,000
21,900,000
21,900,000
Table 6.2 – Wind Generation example calculation results
53
The voltage related deferred capital spend has been assumed to remain constant across all scenarios.
-169 -
Technology
No Gen
Location
-
CHP (natural gas fired)
Mid Trunk
End Mid Trunk
Spur
End Trunk
5km 38kV
Feeder
Cost / Benefit
Connection Cost
0
-€ 250,000
-€ 250,000
-€ 250,000
Displaced Energy
Loss Benefit
-€ 250,000
0
€ 478,004
€ 478,004
€ 478,004
€ 478,004
0
€ 2,428,284
€ 231,793
€ 511,448
€ 235,263
Voltage Benefit54
0
€ 682,083
€ 82,868
€ 323,528
€ 596,879
CML Benefit
0
€ 17,637
€ 17,637
€ 17,637
€ 17,637
Asset Benefit
0
€ 988,690
€ 654,595
€ 673,957
€ 294,754
Transmission Benefit
0
€ 1,126,549
€ 1,126,549
€ 1,126,549
€ 1,126,549
Emission benefit
0
€ 229,442
€ 229,442
€ 229,442
€ 229,442
Social Benefit
0
€ 203,288
€ 203,288
€ 203,288
€ 203,288
Combined Benefit
0
€ 5,903,976
€ 2,774,174
€ 2,921,776
€ 2,592,548
Fuel Benefit (kWh pa)
0
8,591,538
8,591,538
8,591,538
8,591,538
Table 6.3 – CHP (natural gas fired) example calculation results
From the results of these example calculations the following observations can be made:•
The value of the loss benefits is very sensitive to generator location on the network (mid point along the
trunk being the best location) due to the contribution to the benefit calculation from the avoided energy
losses due to the plant location;
•
The value of the displaced energy is dependent on the operational profile of the generation plant and
the resultant load factor on the system. The above examples have been calculated assuming 65% LF
before connection of the generation and 64% LF with the generation operating and it is recognised that
there are discrepancies between the displaced energy values and the losses that would not appear when
the annual generation output and system demand load profiles are utilised;
•
The main items of value all include energy related components i.e. Displaced Energy, Loss Benefit and the
transmission benefit;
•
Asset based benefits will require access to auditable capital expenditure plans for the distribution
network and the ability to discriminate between load related and voltage related capital expenditure;
•
The value of the CML benefit is marginal;
•
The values for the majority of the benefits are significant having been projected across a fifteen year time
horizon;
54
The voltage related deferred capital spend has been assumed to remain constant across all scenarios.
-170 -
•
The recognition of the various benefits will need to be made either on a cash basis through offsetting
connection costs or on a societal basis similar to the arrangements under the Public Service Obligation
that support the social generation plant.
6.17
Issues of note
•
How are the identified benefits to be allocated between the Generator, Utilities, System Generation and
Customers? Some may be able to be ‘allowed’ within the regulatory pricing structure for the distribution
system revenues, whilst others, which are more far reaching in their derivation may not be best
administered within the electricity regulatory framework. Any benefits associated with avoided losses,
deferred capex or avoided reinforcement could be used to offset the connection cost for the generation
plant.
It is expected that further consultation will be required within the industry in order that
multilateral agreement is achieved on the final sharing mechanism.
•
It is recognised that there will be a number of connection offers outstanding for connection of new
demand or generation to the distribution network at any one time. To this extent a judgement will need
to be taken on the probability of the various connection offers being accepted following the embedded
generation network modelling and benefit / cost calculations.
For the purposes of the example
calculations we have assumed that only those offers that have been accepted will be included in the
network model.
•
The calculation of benefits has been done on the basis of the distribution and transmission network
topography at the time the calculations are made. Any benefit that arises from the connection of the
embedded generation plant in terms of released system capacity should be credited to the plant. These
benefits may be recovered by ESB Networks through connection of additional load without the need for
deep reinforcement or from deferral of planned capital expenditure.
•
These benefits appear to have been recognised by ESB Networks within the terms of the latest
Distribution Use of System tariff publication (March 2004) that provides for a sharing payment to be
made to the embedded generator should the assets included within their connection be used to provide
supply to another customer within a 5 year period. Whilst this provides an element of recognition,
however, it is not clear that this captures any benefit that accrues from the deep system reinforcement
that the embedded generator has funded within its connection cost – it appears to only cover the
dedicated connection assets.
•
The benefits have been calculated for the first year of operation of the embedded generation plant. It is
recognised that the plant is likely to be operating for a considerable period of time. Whilst the
generation plant is unlikely to remain in service for the same amount of time seen by utility equipment
(up to 80-90 years in the case of some underground cables). it is reasonable to expect that it will be in
service for up to 15 years. On this basis a 15 year projection is made of the calculated annual benefits /
cost. This 15 year period is significantly in excess of the 5-year sharing period recognised within the latest
ESB Networks DUoS tariff statement;
•
The actual value of the discount factor will need to be subject scrutiny before a final agreement is
reached. It is expected that there may be a need to establish a formal equation to calculate the Discount
factor on the basis of ESB Networks WACC, open market long-term interest rates and market equity
returns with appropriate weightings. In order that the example calculations can be completed the
-171 -
discount factor used for the net present value calculations has been set at 8% given current low interest
rates and inflation;
•
The Marginal Capacity Costs of providing system capacity for an incremental 1kW of system demand will
need to be calculated. This should be on the basis of Modern Equivalent Asset values. The exact
calculation methodology for determining the marginal capacity cost is outside the scope of this review,
however, for the purposes of providing the example calculations we have provided an assumed value;
•
The ‘actors’ within the calculation methodology are predominantly ESB Networks and ESB National Grid.
There may be some debate as to the involvement of an independent external party to undertake
elements of the calculation process in order to protect any commercially sensitive data provided to
enable the calculations. Further, there could be a perception within the development community that
ESB is not necessarily the best-placed company – given skills and experience – to undertake such a multifaceted calculation;
•
Need to explore the impact of the LMP calculation and potential exemption of certain embedded
generation from being exposed to TL’s as they are likely to receive the average marginal price and
therefore will not be subject to the LMP effect. The effect of locational pricing needs to be captured
within the calculations and is most appropriately captured within exit pricing for the energy at the
transmission boundary.
•
There is a reliance on the provision of information relating to the development of the distribution
network by ESB Networks. Such information, unless formally published through a form of Network
Planning statement, could be perceived within the project development community as being nontransparent leading to lack of buy in to any cost / benefit calculation methodology. This suggests that a
formal, periodic statement of the distribution system capital plan be made public in a similar vein to
Transmission System Planning Statements;
•
ESB Networks will need to adopt a transparent position in respect of the statistical data used for
derivation of the expected CMLs for a network. These data should be available from historic fault rates in
respect of the various network assets and items of equipment used by ESB Networks. Again such data
may need to be made publicly available to provide the necessary transparency of input data;
•
It is not envisaged that the impact of operational / maintenance policy on fault rates is drawn out
separately and parameterised within the CML benefit calculation formulae. Rather, in the event of any
policy amendments, the operational / maintenance policy impact on fault rates and restoration times will
need to be accounted for uniformly across all ESB Network asset fault data and this will flow through into
the calculation process via the distribution statistical performance measures – SAIDI and SAIFI;
•
The effect of individual embedded generation plant on the thermal efficiency of system thermal
generation plant is difficult to quantify given that the impact will derive from the combined operating
profile of all embedded generation connected to the distribution system. As per the EirGrid report into
the impact of wind generation on the cost of system operation, the calculation of the impact needs to be
done at a system level not at an individual embedded plant level since the diversity effects of the
embedded plant output needs to be captured;
-172 -
6.18
Methodology Findings
The development of a calculation methodology to deliver a holistic statement of the costs and benefits associated
with the connection of an embedded generation plant to the distribution network, requires significant data input
and modelling effort if it is to present a realistic representation of the impacts. Such modelling will, out of the
necessity to rein in costs and best utilise resources, require a number of simplifying assumptions to be made in
respect of the network configuration, load profiles, generation operation, system generation costs, fuel prices,
system losses etc.
The methodology detailed within this study provides a starting point from which it is possible to identify those
benefits that deliver most value. Some of these costs and benefits are already within the internal cost structure of
ESB Networks (through avoided capital expenditure, loss impacts, displaced load capacity etc) and are being
recovered through the DUoS charges from customers. However, the mechanism for sharing such benefits needs to
be developed such that they are shared equitably between customers and market participants.
-173 -
7.
Market Survey
7.1
System Charges
The charges that can be levied for the connection to and use of the transmission and distribution networks are
regulated by the Commission for Energy Regulation to ensure that a balance is struck between the potentially
conflicting needs of adequate revenue and return for the licencees, security of supply and value for money for
customers in the charging mechanisms adopted by ESB National Grid (Transmission System) and ESB Networks
(Distribution System).
7.1.1
Connection Charges
The connection to the transmission network is treated differently to connections to the distribution network.
Transmission Connections are calculated on a shallow basis with any additional reinforcement works required
beyond those assets for the sole purpose of connecting the new generation or demand to the transmission system
being capitalised within the asset base of ESB National Grid and recovered under the TUoS charging mechanisms.
The cost of providing the connection assets for transmission connections has a contestable element.
The payment terms will be 25% on acceptance of the offer, 50% prior to construction commencement and 25% 1
month prior to energisation. These payment terms will replace the previous requirement to post a Connection
Charges Bond to mitigate non-payment risk in the event that the connection assets are put in place and the
customer is then not able to pay.
Distribution Connections are calculated on a deep charging basis under the Least Cost Technically Acceptable
Solution policy. However, embedded generation connections are required to pay the full deep charges as they are
not liable to pay DUoS on exported energy. Demand connections, depending on their classification, pay a
proportion of the connection asset costs.
Should there by any further connections made to the distribution network within 5 years that make use of the new
connection assets, the original customer will receive a rebate proportional to the extent of the sharing provided the
standard charges (typically used for small demand connections) were not applied.
7.1.2
Use of System Charges
TUoS charges are not applicable for embedded generators with a MEC > MIC and MEC <10MW. However, these
benefits are not passed through in their entirety in the energy supply tariffs although it is almost the case for LV
connected auto producers. Therefore an element of this avoided TUoS charge is retained within the supply business
as additional margin.
-174 -
Table 7-1 ESB Capacity Charge Reductions
Capacity Charge Reduction
LV
99%
MV
63%
38kV Looped
37%
38kV Teed
37%
The Distribution use of system charges are not payable by embedded generation on their exported energy since
they pay for the full cost of their connection assets (including any reinforcements to the network). Embedded
generators pay DUoS charges on any imported energy on the basis of the business user category that best describes
the embedded generators off-take characteristics.
7.1.3
Treatment of Losses
The treatment of losses is expected to change under the new MAE rules to be introduced in 2005. Presently
transmission losses are recovered 100% against system generation – with demand ultimately paying for these
through the energy charges from the system generators. Each generator is allocated a Transmission Loss
Adjustment Factor (TLAF) that is used during the scheduling (system balance) and settlement (loss cost recovery)
processes.
The distribution losses are recovered across all connections through the allocation of a Distribution Loss Adjustment
Factor (DLAF). The DLAFs are allocated to demand customers on the basis of their connection voltage, and to
embedded generation on the basis of the site specific impact that the embedded generator has on the distribution
system. These values are updated annually and subject to approval by the CER.
7.2
Trading Arrangements
7.2.1
Compliance with EU Directive 2001/77/EC
European Directive 2001/77/EC sets indicative reference values for Member States’ targets for renewable electricity
generation55. It also includes a number of provisions to promote renewables, including some concerning access to
the grid (Article 7).
The key points of Article 7 and how they are reflected in the current and proposed market arrangements are
discussed in Table 7.2 below.
55
Directive 2001/77/EC on the promotion of electricity produced from renewable energy sources in the internal electricity market,
27th September 2001
-175 -
Table 7.2 – Current or planned provisions reflecting Directive 2001/77/EC
Article in
Provision in MAE56 or elsewhere
Article content
2001/77/EC
7.1
Requires that renewable generation be
Self-dispatch for units less than 5 MVA
given priority dispatch by TSO, insofar as
effectively guarantees dispatch.
the operation of the grid permits
For larger renewable generators, 2 options
[Note - no mention is made of the
available (although only dispatchable units can
structuring of the price that generators
choose option 1):
should receive for their electricity]
1.
generator offers price & quantity, but
risks not being dispatched;
2.
generator receives market floor price,
but is guaranteed dispatch.
Option 2 allows all renewable generators
access to priority dispatch.
Requires guarantee of the transmission
Dispatch addressed above.
and distribution of renewable electricity
(i.e. effectively that they ensure dispatch).
Current MAE proposals require generators to
Recital 21 of the Directive recognises that
accept the market floor price in return for
this may not be possible for operational
guaranteed dispatch. No arrangements
reasons and allows for financial
currently for compensation in lieu of dispatch.
compensation.
TSO/DSO may provide priority access to
Current allocation of network access does not
the grid system for renewable electricity.
discriminate between different types of
The implication is that this refers to the
generation, i.e. does not prioritise renewables.
allocation of network access rights (i.e. of
available connection capacity).
7.2
TSO/DSO to publish rules relating to how
Rules for connection costs are published by
grid connection and reinforcement costs
ESB Networks and ESB NG 57.
are borne.
Rules to be non-discriminatory and to take
Current rules do not distinguish between types
account of all costs and benefits.
of generation. Deep reinforcement charges do
not take account of benefits of EG.
56
CER/04/214, “Implementation of the Market Arrangements for Electricity in relation to CHP, Renewable and Small-scale
generation”, 9th June 2004
57
CER/ESB/2000/10, “Connection Asset Costs: Guiding Principles”, 12th April 2000
-176 -
7.3
7.4
Member States may require TSO/DSO to
Not taken up at present (except transmission
bear these costs.
reinforcement costs)
TSO/DSO to provide generator with
Connection Offers from ESB Networks and ESB
detailed connection cost estimate.
NG provide cost estimate.
Member States may allow contestability.
Contestability element established for
transmission connections. Contestability
provision for distribution connections in draft
Electricity Bill.
7.5
TSO/DSO to publish standard rules for
Qualitative principles for shared connection
sharing connection costs between all
costs are published by ESB Networks and ESB
generators benefiting from them.
NG.
ESB NG publishes anonymous list of
interacting connections at Transmission and
Distribution level (>4 MW)
Rules to be non-discriminatory and to take
Charges do not take account of benefits to
account of all the benefits to generators,
DSO.
TSO and DSO.
7.6
Transmission and distribution charges
CER currently reviewing tariff structure,
should not discriminate against RE,
including how to reward EG if it provides cost
especially that in remote areas.
benefits (e.g. reduced losses)
TSO/DSO to ensure charges reflect cost
benefits of EG.
From the review in Table 7.2 above, reflecting the benefits of EG in the charging system is the most significant gap in
the current procedures. CER is consulting on tariff structures that include this area58.
The Internal Electricity Market Directive 2003/54/EC59 also includes provisions of relevance to embedded generation
– these are generally aligned with those of 2001/77/EC described above.
58
CER/04/239, Electricity Tariff Structure Review: Alternative Tariff Structures, 1st July 2004
59
Directive 2003/54/2003 concerning common rules for the internal market in electricity and repealing Directive 96/92/EC, 26th
June 2003
-177 -
7.2.2
Perceived costs and benefits of renewable and embedded generation
It is widely recognised that embedded generation can provide benefits from its connection to the distribution
network through avoided losses (if located close to customer demand), additional system security and potential
betterment for supply quality. However, it appears that to date these benefits have been subject to a degree of
oversight within an industry that has been focussed on the implementation and management of a system based
around a small number of large system power generation plant.
The perception of embedded generation within the electricity industry still appears to be that these generators
cause more costs than benefits (which may well be true) in terms of the local distribution network, however, this
view of costs and benefits does not consider wider issues related to the embedded generation operation that need
to be accounted for in order to see the full picture. To the contrary, there is a perception outside the electricity
industry that the adoption of large capacities of wind and other forms of renewable energy generation will provide a
panacea for the potential future environmental problems.
Both perceptions are equally valid for those who hold them, however, neither one is based on a sufficiently broad
view of the overall benefits that embedded generation plant may have outside limited terms of reference.
7.3
General Market Issues
The present market structures for the connection and use of the transmission and distribution network are
undergoing a process of review that is still running its course. A number of elements are presently being consulted
on within the scope of the new Market Arrangements for Electricity due to be introduced in 2005. These include:
•
Relevance of Transmission Losses within a market that includes Locational Market Pricing;
•
Introduction of Ancillary Services market;
•
Financial Transmission Rights mechanisms;
•
Costs to be recovered through the TUoS charging mechanism when the new MAE is introduced.
Within the context of this relatively fluid environment the principles behind the allocation of the costs and sharing of
benefits from embedded generation may be significantly altered. However, the costs and benefits identified within
this study can be reallocated to reflect any changes to the market rules and charging mechanisms.
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8.
Stakeholder Views
8.1
Stakeholder Questionnaire
In order to gain a view of the opinions of industry stakeholders, a questionnaire was sent to a representative
selection of organisations. The full text of the questionnaire is included in Appendix E, along with a list of the
organisations consulted. The aim of the questionnaire was to gather views on how embedded generation is
encouraged at present, and how this could be improved in future, as well as what the costs and benefits of such
generation would be. Questions covered the broad themes of:
8.2
•
Connection and use of system charges
•
Trading arrangements and market issues
•
Technical issues
Response from Stakeholders
Of the ten stakeholders questioned, seven responded within the timeframe for inclusion in this report. As might be
expected, certain stakeholders focussed on particular questions, and the bulk of the responses covered the areas of
charges and trading arrangements for renewable electricity generation.
8.3
Analysis of stakeholder responses
In order to preserve anonymity given the small number of stakeholders consulted, the following analysis does not
identify specific respondent comments. Instead, it seeks to provide a summary of the viewpoints expressed in a
number of key areas.
8.3.1
Connections
The area of deep connection charges on the distribution system received a number of comments, and unsurprisingly
there was a wide range of opinions. There was a view from some generators that they are being asked to bear the
full cost of reinforcements that others also benefit from. Another respondent, however, pointed out that generators
do not pay DUoS charges once connected.
There were a variety of comments on how to improve the connection regime to encourage embedded generation.
Proportional charging of deep reinforcement costs was suggested as a means to allocate costs amongst all the
beneficiaries. Other suggestions included the development of common processes between the DSO and TSO, the
recovery of connection costs through use of system charges and the discouragement of continual reapplications by
some developers that negatively affect others.
Contestability of distribution network connections was supported by most respondents, who view connection costs
as a major barrier to the deployment of embedded generation.
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8.3.2
Treatment of Losses
There was a general wish amongst developers to see a more transparent process for calculating the Distribution Loss
Adjustment Factor (DLAF).
A specific suggestion to promote embedded generation was to remove the Transmission Loss Adjustment Factor for
generation whose output can be shown never to reach the transmission system. However, another stakeholder
noted that a generator connected to a 38 kV substation and considered to be embedded may actually export
through the transmission system and thus cause losses without having to bear the cost.
One respondent noted that the introduction of Bulk Supply Point metering should allow better measurement of
losses.
8.3.3
Market Arrangements
There was a broad view that the 30 MW limit for self-dispatch may be a barrier to wind farms above this threshold.
However, it was also suggested that central dispatching of large wind will be needed in order to optimise wind
penetration. This was linked to a desire for the subsequent curtailment to be fully compensated.
Generators strongly stated a desire for new market arrangements to be bankable, in order to allow a broad range of
generators to enter the market. They were also of the view that CfDs were helpful but insufficient to provide
certainty to investors, and that investment in embedded generation would continue to be deterred by the
uncertainty inherent in market pricing. Other respondents felt that CfDs would provide sufficient investor
confidence, however.
A number of respondents felt that the single top-up/spill price in the new arrangements are an improvement over
the current regime.
8.3.4
Location Pricing
Some respondents believed that location marginal prices (LMP) will tend to discourage embedded generation
(principally remote wind farms), since much of the wind resource is in remote locations where LMP will be low. One
respondent commented that increasing wind generation at a particular location would cause the LMP to drop even
further. These stakeholders believed embedded generation should receive the Uniform Wholesale Spot Price (UWSP)
or a fixed tariff. One suggested embedded generation should receive the UWSP plus a premium to reflect
environmental benefits.
Other respondents felt that all generators above a certain capacity should receive the LMP, reflecting the value of
their output at that location and sending the appropriate market signals.
8.3.5
Flexibility of generation
The new arrangements will favour flexible plant due to its ability to respond rapidly to changing market prices. There
was an expectation among respondents that this will encourage greater flexibility from thermal plant. However, it
was commented that wind is not genuinely flexible – due to the nature of the resource, it cannot be operated at will
and therefore cannot respond readily to the market. It was felt that this would place wind embedded generation at a
disadvantage versus thermal plant.
-180 -
The potential for embedded generation to see negative prices was considered by some to be detrimental to wind
generation, although others commented that actual instances of negative prices were likely to be rare. Other
respondents considered that all generators including embedded generation should see negative prices in order to
encourage flexibility.
The possibility of embedded generation receiving a UWSP averaged over a week or month was suggested by one
stakeholder as a means to protect embedded generation from market volatility, although others were keen for any
support mechanisms to be completely outside the market to avoid possible distortion.
8.3.6
Reserve Costs
The question of allocating reserve costs unsurprisingly divided respondents between those who supported the
“causer pays” principle, and those who believed that they should be allocated so as not to discourage wind
generation.
One respondent commented that the allocation should be on the basis of all the characteristics of each technology.
For example, this would include aspects such as ability to reduce emissions as well as capability to provide reserve.
8.3.7
Small vs. large generators
There was general recognition of ESB’s dominant position in both overall generation and renewables / embedded
generation, and concern over how this may hinder the access to investment needed by smaller generators.
Respondents commented that careful regulation was necessary to ensure that small generators can participate in
the market.
8.3.8
Technical Issues
A number of technical comments and suggestions were made by stakeholders in the general area of encouraging
EG:
•
Allowing constraining-off as part of the design for wind farms could allow greater capacity to be
connected, or the same capacity to be connected at lower cost. For example, planned constraining-off
during the few hours per year that limit connection capacity (e.g. windy summer nights) might allow a
larger capacity to be connected and overall embedded generation output to be higher.
•
The proposed requirement to provide ride-through-capability needs to be considered in light of the extra
burdens it imposes on wind generation
•
Permissible voltage margins on the distribution network are narrow, and are a barrier to embedded
generation
•
The use of Remedial Action Schemes to strengthen networks would allow higher penetration of
embedded generation.
•
Improving information about interacting connection applications would reduce the uncertainty from this
source
•
Smaller embedded generation could be facilitated by requiring larger projects to connect to the
transmission system.
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8.3.9
CHP
Only a limited number of stakeholders responded to the questions on CHP. A specific area of concern was the
charging policy based on Maximum Import Capacity (MIC) and Maximum Export Capacity (MEC), which can result in
a CHP generator who is a net exporter of electricity still being classed as a demand user and thus paying DUoS
charges. A tariff based on actual volumes of electricity rather than capacities was suggested.
8.3.10 Microgeneration
There was a general view among stakeholders that net metering would be the appropriate means to meter very
small generation (e.g. domestic CHP). Meters with several different tariff bands could be used to make sure the timeof-day value of the output was appropriately rewarded.
8.4
Key Findings of Stakeholder Survey
There was a range of views on many issues, which is not surprising given the range of stakeholders questioned. This
section attempts to summarise these views and identify key themes.
There was a general acknowledgment of the need to reduce uncertainty in order to encourage deployment of EG.
Developers’ underlying concern was the bankability of projects, rather than on what the market mechanisms are per
se. Compensation or protection from the variations in a large market pool was a key theme. Other respondents were
more concerned with ensuring market mechanisms provide a level playing field for all generators. A separate,
predictable support mechanism outside the market might best meet the range of needs expressed.
Costs of connection and reinforcement associated with new embedded generation connections clearly need to be
allocated in some manner, although existing deep connection charges are viewed as a discouragement to
embedded generation by most generators. Repayment of costs over a number of years might mitigate this,
effectively converting the upfront capital cost into a form of DUoS charge. Allocation of part of the costs to other
beneficiaries of the reinforcement would also encourage embedded generation.
There were differing views on flexibility of generation. While the proposed market arrangements would encourage
generators to be more flexible, it was pointed out by some that wind is inherently inflexible – due to resource
intermittency, it cannot always choose when to generate (although it can choose when not to). There is therefore a
concern that wind may be disadvantaged as thermal plant makes itself more flexible.
On the treatment of losses, there was a general desire for a more transparent means of calculation and allocation. An
underlying theme was to avoid general limits or definitions that would result in some embedded generation causing
losses and not being charged, and vice versa.
The question of location pricing divided respondents between those believe that it will discriminate against wind
generation (where the resource is often best in remote areas where LMP is low), and those who believe that all
generators should receive price signals related to location. However, there was general acceptance that only
generators above a certain capacity should receive LMP, while those below would receive the UWSP. CER have now
set this cut-off limit60.
60
See CER/04/214, “Implementation of the Market Arrangements for Electricity (MAE) in relation to CHP, Renewable and Small-scale
Generation”, 9th June 2004
-182 -
9.
Treatment of Costs and Other Issues Related to Connection of Embedded
Generation
9.1
Purpose
The purpose of this section of the report is to review the approaches for cost / benefit sharing within a number of
different markets. These markets are at various stages in their process of moving towards full competition for the
supply of electricity, have various degrees of renewable embedded generation connections at distribution voltages
and have differing market models for wholesale electricity transactions.
The intention is to enable an overview of the various approaches adopted and, where possible, identify those which
have relevance for the treatment of embedded generation costs / benefits within the Irish market.
9.2
International Review
The jurisdictions reviewed are Australia, New Zealand and Singapore. A view of a number of mainland European
markets is also included. The documentation reviewed included the Market Rules, Grid Codes and other relevant
regulatory documentation.
9.2.1
Australia
The Australian market is split into 5 distinct markets – Australia Capital Territory, Queensland, South Australia,
Victoria and New South Wales. Each market retains its own independent local regulatory body with distribution and
transmission price regulation on the basis of a CPI-X formula with a revenue cap.
The countrywide market rules are governed through the National Electricity Code Administrator – NECA. NECA is a
company formed by the five participating jurisdictions specifically to manage and maintain the market rules. Final
determination for any unresolved disputes within the terms of the market rules will be made by referral to the
Australian Competition and Consumer Commission (ACCC).
The electricity market has been implemented to provide open access to transmission and distribution networks and
to enable inter-state energy trading through the national electricity market. This national electricity market is
operated and maintained by the National Electricity Market Management Company – NEMMCO. The NEMMCO has
responsibility for the scheduling and dispatch of system generation plant and managing transmission system
constraints.
Connection Costs
Connection costs to the Distribution Networks is on the basis of a negotiated
connection agreement that must comply with the minimum standards, or, at the
request of the applicant, provide a service to a higher standard. Any costs
associated with a requested higher standard of service are attributed to the
applicant 100%.
Discussions are underway into the possibility of a dual connection charging
approach to separate small connections (say a domestic Photovoltaic project)
from larger connections to the distribution system.
TUoS Treatment
Generators connected to the Distribution Network are passed through the full
value of the avoided TUoS costs arising from their operation during the 10 highest
-183 -
demand periods on the system. This calculation is undertaken each year and
utilises meter readings for peak capacity and energy.
DUoS / Asset Benefit
Once connected to the Distribution Network the generators and customers are
required to pay ongoing DUoS charges on the basis of their respective use of the
Distribution Network (for entry or exit). The charging mechanisms recognise that
the Distribution Network continues to be developed to cater for new load or
replaced to cater for life expired assets subject to criteria on allowable pass
through of costs. Consequently the generators and customers are required to
support the cost of new network investments (categorised into large network
investments and small network investments) pro-rata to the benefit they receive
from its installation.
New Large Network Assets - Benefit calculation allocates to generators as a class
then to generators individually pro-rated to their proportion of the benefit
received. This percentage proportion is then used to determine the capital
cost recovered from each generator. All other costs associated with the new
network investment are recovered from the remaining customers via the TUoS
or DUoS charges.
Small Network Investments - Cost of new small network investment is split
across generators and customers connected to the relevant network pro-rated
to their benefit from the investment. The proportion of costs allocated to the
generators is then recovered through a capacity based charge – New Small
Network Investment Charge – from all generators. The remaining proportion
of the costs are recovered through the TUoS or DUoS charges as appropriate.
Losses
Calculation is made by the Distribution company and sharing is open to
negotiation between the parties as part of the commercial arrangements for the
connection to the distribution network.
Emissions
Not recognised within the benefits
Displaced Load
Displaced load capability of embedded generation is not recognised within the
connection calculation methodology.
Some discussions are underway into the possibilities of allowing rebates to be
payable to embedded generation to the extent that other customers utilise assets
that the generator originally paid for as part of their connection to the
distribution network. Any rebates made could be allowable within the regulated
revenues of the distribution company.
Displaced Energy
Not recognised within the benefits.
Social
Not recognised within the benefits
CML
Ability of the embedded generation to provide support to the distribution
network local to its connection is not formally recognised within the connection
methodology, however, it has been recognised that it can provide a contribution
-184 -
to system security.
Information Availability
One state has required that the distribution network operator provide a
distribution planning statement covering a 5-year time horizon to address the
increasing recognition that the information provided about the distribution
network is not sufficient in quantity or detail to provide market signals to
embedded generation developers in respect of plant siting.
Asset Benefit
Discussions are underway to explore the potential to recognise avoided
distribution network investment costs calculated as a Net Present Value of the
avoided network investments. It is proposed that these benefits be shared to the
extent that the minimum share should be that amount of the benefit that would
allow the generator to be commercially viable.
Table 9-1 Australian Market Summary
Where costs or benefits are recognised there will be a need to identify a suitable allocation methodology. Within the
Australian context the following allocation methods are under consideration.
Costs Allocation Methods
Market Analysis – over range of scenarios for demand, plant operation (system
and generating), other planned augmentations and ancillary service provision.
NPV calculations made on the basis of range of Discount Factors and utilise the
changes in Generation variable costs, reduced load costs and change in
generation total profits. Allocation to class proportionate to total benefit for the
class and then on a capacity basis within class.
Network Analysis – substitutes each generator on the system at the Regional
Reference Node in turn to determine their incremental impact on the new asset.
Only positive increases are counted. Allocation of the costs is prorated against
the relative use the generator makes of the new asset.
Energy Deprival – uses the ratio of the reduction of unserved energy for loads to
the total additional energy able to be delivered to the market by the generators
as a result of the new investment; and the additional energy supplied by
generators less the reduction in unserved energy all divided by the additional
energy. These ratios are used to deliver the split of benefit between load and
generator classes.
Incremental Investment – a base line taking into account the cost of load related
investment is used to determine the extent of any generation related
incremental investment required. Any increase in investment due to the
generation will be allocated with the load class picking up the proportion that is
equivalent to the base line scenario with the excess being picked up by the
generators.
Table 9-2 Australian Market Cost Allocation Methods
-185 -
9.2.2
New Zealand
New Zealand has recently replaced the NZ Electricity Market (NZEM) with Electricity Governance Regulations (EGR)
to address concerns about the ability of the NZEM structures to deliver security of supply and optimum energy use
given the reliance of the NZ market on Hydro-electric generation. Such generation being energy constrained.
•
The new arrangements have established a System Operator to whom all parties (including embedded
generation greater than 1MW in capacity) must provide capability statements.
•
Embedded generators may trade power in the market, however, they will be required to enter into
appropriate ‘conveyance’ arrangements with the DNO to get the power to the transmission system entry
point.
•
Embedded generation greater than 10MW must provide technical information to the System Operator
(SO) on a regular basis or as and when requested by the SO. This information will include provision of
maintenance plans for each year;
•
Embedded generation is not required to provide offers to the market;
•
The SO will contact those embedded generation plant which it determines need to participate in the
offer processes;
•
Electricity Commission has been established specifically to oversee the operation of the electricity market
under the auspices of the Electricity Governance Regulations.
Item
Connection Costs
Comments
New asset payments on a deep basis restricted to the first point of connection
beyond 11kV up to the next voltage level.
To the extent that the generator connects to assets installed <15yrs ago, or
which have been upgraded <15years ago and for which contributions are still
being made by other distributed generation - the new generator will contribute
to the cost of the line.
Connection contracts vary between distribution companies and there are
efforts underway to seek the implementation of standard contracts for
distribution generation connections.
TUoS
The distribution companies will provide an 85% pass through of avoided TUoS
costs benefit
DUoS
Any embedded generation connected to load will only pay DUoS charges on
the basis of the imported electricity amounts – no additional charges will be
levied ion the exported amounts;
Embedded generation should pay reasonable incremental operational costs for
the system, but not a full use fee. Such ongoing operations charges should be
restricted to 5% of the amount chargeable to an equivalent sized load. Also this
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charge will be netted off any TUoS benefit received;
Asset Benefit
Deferred network investment payment over minimum time horizon of 10 years.
The uncertainty of network investment is to be factored into this NPV
calculation;
Not clear how transparency will be provided to the investor on the calculation
method for the incremental costs;
Energy
Clear rules have not been created for the interconnection of embedded
generation in the lines networks and for trading of small amounts of energy
from embedded generation in the market.
Emissions
Not included in the calculation
Social
Not included in the calculation
Fuel
Not included in the calculation
Table 9-3 New Zealand Market Summary
9.2.3
Singapore
Singapore has a newly established wholesale market structure – having gone live in January 2004. The market is
split between the Generators, Retailers and monopoly Transmission / Distribution companies. The transmission
voltages range from 66kV upwards (inclusive) and distribution from 22kV (inclusive) downwards.
Connection to the transmission or distribution network must be done through a proscribed application procedure.
The generation plant owners / operators need to obtain a generation licence for their facilities prior to operation.
This rule applies unless the generator falls within the exempt generation category:•
Less than 10MW nameplate capacity then exempt from generation licence;
•
If between 1MW and 10MW nameplate and connected to the transmission system then generator is not
exempt;
Charging:
•
Charges levied on the basis of the required connection capacity. This connection capacity is fixed over the
first 5-year period following the connection. If the customer disconnects during this time any shortfall of
the 5-year pmt will be recovered. (Stranded Asset avoidance);
•
The capacity may be reduced after the initial 5 year period subject to some restrictions;
•
All customers are charged Use of System charges on the basis of net imported energy during each
settlement period. I.e. if no import then no UoS charge. If import to generating plant is through distinct
import connection then the Connection Capacity Charge applies;
-187 -
•
High voltage connections are made on the basis that the costs of making the connection to the Singapore
PowerGrid system are borne by the customer / generator (shallow charging). Connection is designed for a
single contingency event. Connection to higher standard than (n-1) will need to pay for this in full (deep
charging);
•
Customers can choose to have Singapore PowerGrid pay for and have ownership of any dedicated
substation / assets in return SP can sell on any excess capacity not immediately required by the customer.
However, the customer retains a capacity call option on Singapore PowerGrid up to the capacity of the
connection assets;
The Singapore approach to renewable energy is in a fledgling state. As such there is a focus on the conversion
of extant system oil fired generating plant to gas firing to capture the reduced emissions and improved
efficiency available from gas generation technology over oil. To this end the charging mechanisms for
embedded generation reflect the shallow costs for connection to provide an n-1 security with additional costs
for higher standards being fully to the customers account (deep charging). The generator pays use of system
only to the extent that they have a net import or have a separate import connection point for station supplies.
Sharing of avoided loss, transmission use of system charges etc is not currently specified within the market
documentation and therefore it is presumed that any additional benefits of embedded generation connection
fall 100% to the customers local to the plant (voltage benefits, security of supply etc) or are determined under
bi-lateral negotiations with energy retailers (TUoS avoided, distribution losses etc).
9.2.4
Germany61 62 63 64
The German electricity market is divided between the large transmission system and system generation plant
owners and operators such as RWE, EoN, VEAG, BEWAG etc and the smaller, municipally owned distribution network
operators. The market is open for 100% of the customer demand.
The distribution network operators have obligations to ensure the continued safe and reliable supply of electricity to
all connected customers, however, the distribution system operator may, in exceptional cases, agree with the
customer to provide supply outside the required limits.
The distribution network operators are responsible for ensuring that they have sufficient control over the reactive
power flows in the distribution network to maintain the voltage within the specified limits. Typically this is achieved
through the operation of reactive compensation in the network and through the control of distribution connected
generation plant via commercial arrangements specifically to cover these issues.
There are requirements placed on the network connected generation units to provide the following information to
the distribution network operator:
•
Measured values of current, voltage and power;
•
Limit values for active and reactive power;
61
EU Energy Directorate, 3rd Benchmarking Report, March 2004 (europa.eu.int)
62
German Network Operators Association (Verband der Netzbetreiber)
63
RWE (www.rwe.com)
64
EoN (www.eon.com)
-188 -
•
Circuit breaker settings / step switch positions;
•
Protection signals;
•
Generating unit start up and reduction of output
The distribution network operator has obligations to inform the connected generation plant of any network
congestion that arises due to network disturbances an scheduled or current switching measures that restrict the
generating units output.
Transmission Connection Charging
Access to the transmission system is provided under negotiated
third party access agreements negotiated on a bilateral basis
between the DNO and the generator. Both generation and
demand pay deep connection charges (including maintenance,
reinforcement and operating costs increases associated with the
connection).
TUoS Charging
Transmission use of system charging is payable only by demand to
recover the ongoing costs associated with the maintenance,
renewal and operation of the network.
The charges are split to identify the metering costs, kW capacity
usage and kWh energy usage. These are payable monthly or
annually. Customers are also able to pay for reserve capacities
(non-firm capacity) and reactive power services.
Distribution Connection Charging
Demand and generation pay for the connection to the distribution
network on a deep charging basis. The generation also pays for
the maintenance, renewal and operating costs of the connection
assets.
DUoS Charging
Use of system charges are payable by demand customer only.
However, embedded generation is entitled to receive payment in
lieu of avoided Use of System costs from the higher voltage levels.
These payments are applicable for non-renewable based
generation (renewable plant receive support as a result of the
Renewables Energy Act).
Payments for smaller embedded
generation without power metering is made on the basis of
seasonal synthetic output profiles for the units.
Further, where the embedded generating plants have a load factor
of >30% it is considered that the DNO is able to utilise the output
to offset the system capital expenditure requirement. Such offset is
proportional to the generating plant availability. The loss of
generation during maintenance outages is then provided for by
the DNO under a system reserve capacity contract from the
transmission network.
Table 9-4 German Market Summary
-189 -
9.2.5
Spain65 66 67 68
The Spanish market comprises of the market operator (OMEL), the grid operator and asset owner (REE) and the main
electricity supply and distribution companies (Union Fenosa, Iberdrola and Endesa). All activities in the electricity
market are governed by the terms of the Royal Decree 1955/2000. The electricity market is regarded as being fully
open with an active energy regulator and legal separation of Distribution system operators. The generation market is
still dominated by the largest three generation market incumbents.
Transmission Connection Charging
Generators and demand make payments for connection to the
transmission system that include the costs of the connection
assets and any other reinforcement necessary to provide the
capacity required. Users that subsequently connect (within 5
years) to the transmission system and use the same assets are
required to make a contribution to the original cost of the
connection assets pro-rata to its own connection capacity.
TUoS charging
Only demand pays use of system charges that include both
capacity and energy components with reactive energy charges
being applied in the form of a surcharge or reduction dependent
on the actual use of reactive energy by the demand.
The network use system charges include distribution and
transmission use of system charges.
Distribution Connection Charging
Demand customer connection costs are paid through regulated
charges on the basis of the kW capacity requirements with the
pricing varying with capacity and voltage level. Generation plant
is required to pay for the full connection costs. Rebates are paid
if new users connect to the assets within 5 years of
commissioning.
DUoS
Distribution use of system charges are rolled up into the network
tariffs. See TUoS charging above.
Losses
Transmission Loss factors are calculated by REE for each
transmission system node and published on a daily basis ex-post.
Table 9-5 Spanish Market Summary
65
Comision Nacional de Energia (www.cne.es)
66
Endesa (www.endesa.es)
67
Iberdrola (www.iberdrola.es)
68
European Union Energy Directorate (europa.eu.int/comm./energy)
-190 -
9.2.6
Netherlands 69 70
The Dutch electricity market is regarded as being open to competition for the medium and large industrial and
commercial customer base. Distribution companies have legal separation from the energy supply and transmission
companies, and a regulator is in place. Further the generation market is regarded as being competitive given that
the market share of the largest three generation companies is around 33% of the total generation capacity.
Transmission Connection Charging
The connection charging includes an initial connection charge for
making the break into the grid system. The user will need to pay
for the costs for the connection assets over and above that allowed
for within the initial connection charge. Additonally, there is an
ongoing charge to cover maintenance of the assets and future
refurbishment costs (the latter item can be deferred provided that
the user pays in full when the assets need replacing)
TUoS
Transmission use of system charges are levied on both generation
(25% of total revenue) and demand (75% of revenue). These
charges include costs for metering services (excluding provision of
the meter). For demand the charges are split 50% as a stamp
charge on the basis of the contracted capacity and 50% on the
basis of the energy off take.
There are separate charges for ancillary service charges and
reactive energy use.
Distribution Connection Charges
Connection charges are comprised of the initial investment costs
and the maintenance costs to be constructed to include a one-off
contribution, compensation for capital expenditure of reusable
and compensation for maintenance costs. There are no special
provisions for renewable or CHP generators.
DUoS
Charges and billing determinants vary by voltage level.
Table 9-6 Dutch Market Summary
69
European Union, 3rd Benchmarking Report on Electricity Market Liberalisation, March 2004
70
Tennet (www.tennet.nl)
-191 -
9.2.7
Norway 50 71
The Norwegian electricity market is regarded as being full y open to competitive energy supply. The transmission
asset owner and system operator are separated by corporate ownership, with the distribution companies providing
separate regulatory accounts. A regulator is in place and the generation market is regarded as being competitive
with the market share of the largest three generating companies being ~25%.
Transmission Connection Charging
The grid companies recover the connection cost through an
investment charge or connection fee. Investment charges are over
and above the regulated income cap for the companies.
Generation and demand pay shallow charges for connection with
refunds applying to assets within a ten year period following
commissioning. There are no special provisions for renewable or
CHP based generation.
TUoS
Transmission use of system charges are levied on the basis of
energy (kWh), capacity (kW) and peak load (kW). The charges are
split between generation (30%) and demand (70%). Capacity
charges are on a stamp basis with energy being on the basis of use
and determined on a nodal basis.
Distribution Connection Charges
The connection charging is based on shallow charges to the
connection point with both customers and generators paying for
the dedicated connection assets. There are no special provisions
for renewable or CHP generators.
DUoS charges
These vary by voltage level.
Table 9-7 Norwegian Market Summary
9.3
Recommendations for Irish Market
The various markets reviewed have not provided any strong evidence for pro-active support for renewable and CHP
generation plant within the charging structures for connection and use of distribution and transmission systems.
Germany appears to provide the most pro-active support through the provision of feed-in tariffs at the transmission
level which filter through to the generation users in the form of offset payments made to them by the distribution
companies.
Connection charges are generally applied on a deep charging basis for embedded generation plant, with some
jurisdictions applying use of system charges to both demand off- take and generation export onto the system.
Where this is the case the split in terms of recovery of the allowable use of system revenue is of the order of 30%
from generation and 70% from demand.
A number of jurisdications have adopted a rebate methodology to enable future offset of the deep connection costs,
with the cut-off for rebates ranging from 5 years out to 15 years.
71
Stattnett (www.statnett.no)
-192 -
In developing recommendations for the Irish market the elements identified within the calculation methodology
have been grouped into three categories – system focussed, energy focussed and macro-economic. Each item is
discussed individually with a view to identifying possible mechanisms for their treatment in the Irish market.
9.3.1
System Focussed
These are the benefits / costs that can be recovered or controlled by the distribution and transmission operators.
Therefore there is the capability within the regulatory framework to determine how the allocation of these costs and
benefits should be made. The items considered to fall into this category are:
Losses – to the extent that losses are saved through the operation of the embedded generation the
benefit accrues to the distribution company since cost of the system operation will be reduced. Therefore
the allocated distribution loss factors will be too high leading to over-recovery of use of system charges
from the energy suppliers using the network and, ultimately, the end customer.
Recognition of this could be through applying an uplift to the generator distribution loss factor that
represents a share (say 85%) of the avoided system loss, this uplift could be applied for a defined period of
time (say 5 years) – after which the uplift is incorporated into the embedded generators loss factor and is
removed from the allowable use of system revenues. This will allow regulatory oversight of the revenue,
provide ESB with some benefit initially and the customer with the long-term benefit through reduced
losses cost;
•
Asset Benefit – sharing of this benefit should be in proportion to the use made of the distribution system.
The demand customers connected to the network will see this in the long term through downward
movement in the DUoS charges following regulatory reviews (to the extent that reinforcement has been
deferred due to the embedded generation connection).
Since the embedded generator is effectively funding the assets that provide the ability to defer or delay
capital expenditure, any benefit should be used to offset the cost of the deep connection cost to the
generator. There is a strong case to argue that the full amount of any benefit should be utilised.
The deep connection charging could be replaced with shallow charging (dedicated connection assets only)
and a generator DUoS charge levied on the exported energy from the embedded generation site. These
DUoS charges could then provide locational signals and a mechanism for apportionment of the benefits to
embedded generators.
Clear and transparent rules for defining the security contribution of the various types of embedded
generation will need to be established to allow consistent calculation of the embedded generation
benefits.
Availability of information is key to the efficient performance of any market. To assist in achieving this
objective it would be worthwhile reviewing the value for a regular publication of the distribution network
development plans in the form of a statement that provides indications to prospective developers as to
those areas on the distribution network that are best able to accept embedded generation capacity.72
Whilst there is an argument against such publications given the fluid nature of the distribution network, it
is expected that this argument will weaken as the DNO is required to evolve the network into a more active
‘transmission-like’ system.
72
Such a statement is provided by Scottish Power for its Manweb distribution network in the UK.
-193 -
Voltage Benefit – on the basis that the generation plant provides reactive power into the local
distribution system the distribution company will benefit to the extent that:(i)
the apparent power factor at the transmission exit point improves (i.e. they require less reactive
energy) and therefore they incur lower reactive energy charges73. The reactive energy production
from the embedded generation plant should be assigned a value and payments made on the basis of
metered reactive power production. Any payments made by the distribution company to embedded
generators would be on the basis of the reactive power charge within the published DUoS tariff for
the connection voltage level. Further, those payments made to the generator for reactive power
should be allowable within the distribution revenues and therefore will pass through to the energy
supply businesses and ultimately the customer, and;
(ii) the voltage profile on the local distribution network improves such that any capital expenditure
required for voltage reasons could be deferred. As has been proposed for the asset benefit, any
voltage benefit should be used to offset the cost of connection for the embedded generator;
(iii) consideration is given to the possibility that the generator may provide voltage support ‘on-demand’
for the DNO at the time of designing the generation connection. A mechanism will be required to
allow the DNO to recover any additional operational costs associated with active distribution
networks. Identifying sections of network to be used to pilot such active network management
techniques would enable costs to be ring-fenced on a project by project basis and also allow network
performance to be monitored against the actions taken. The identification will need agreement
between the DNO and the embedded generation connected to that section.
CML Benefit – is dependent on the statistical performance of the network. The value of the CML benefit is
rather more intangible than the other benefits discussed above. The impact of an embedded generation
connection on the local demand customers may well improve the overall supply quality and reliability.
However, whilst customer payments may be made for the loss of supply lasting longer than a specified
duration, it is only when significant penalties and incentives are placed on the distribution company that
the financial balance begins to favour generation islanding schemes.
Transmission Benefit – comprises the asset and losses elements that apply to the distribution system, but
at a transmission system level. These benefits will accrue to the transmission company to the extent that
the embedded generation connects to the distribution network and operates reliably. The benefits will
initially be to the Transmission companies account as an over-recovery or ability to re-divert the capital
expenditure to other projects within the regulatory period. Such over-recovery or re-direction will benefit
other customers connected to the transmission system or indirectly, the customer through reduced pass
through charges.
The exemption of smaller embedded generation plant (MEC<10MW and MIC<MEC) from DUoS charge
payment means that there is no mechanism in place to allow the benefit to flow through to the generator.
Any sharing of this benefit would need to flow via the distribution company that has the contractual
relationship with the transmission company and the embedded generator.
One mechanism to release this benefit to the embedded generators in the absence of generator DUoS
charging would be to establish reward for the generators proportional to their contribution to the reduced
capacity requirement at the transmission-distribution interface.
73
Assuming that the Reactive Energy charging is implemented as per CER/04/239 1 July 2004.
-194 -
9.3.2
Energy focussed
This is the Displaced Energy benefit that are derived from avoided energy costs that will be passed through to the
energy supply companies, prior to reaching the customer. Given that the renewable plant are able to sell their
output to ESB PES and ESB PES subsequently recovers the cost difference between embedded plant output price
and the BNE price through the Public Service Obligation (PSO), it is not clear how any calculated benefit can be
shared since the PSO already provides support for the embedded plant output over and above the cost of the new
entrant system generation plant.
The main difference arises in the approaches adopted by the PSO and this proposed calculation methodology. The
PSO approach assumes that all renewable generation capacity will displace the best new entrant cost of generation.
However, the renewable generation output displaces operating generation plant. The type of plant that will be
displaced depends on the generation profile of the embedded generator and therefore the price of the avoided
energy will vary accordingly. To the extent that there is a positive benefit arising from the displacement of energy
(i.e. the cost of the system plant energy is greater than the cost of the embedded plant energy), the benefit should
be passed through to the end customer as a reduction in the PSO levy applied by ESB PES to the customer energy
sales.
The embedded generator is indifferent to this since they are receiving their required energy output price that is
supported by the PSO. There may be an argument for the embedded generator to receive a share of the benefit
from any upside, however, the converse would also need to be true to ensure symmetry and the embedded
generator would therefore need to accept that they incur a cost where the benefit is negative. This is unlikely to be
acceptable as this would undermine the support provided by the PSO in the first instance.
9.3.3
Macro Economic
Those benefits that are considered to require treatment within a macro-economic context are - Emissions Benefit,
Fuel Benefit and Social benefit. However, there is no direct contractual link between the embedded generator and a
third party that allows these benefits to be realised directly through existing mechanisms.
Emissions Benefit – to date only really includes value for avoided carbon dioxide emissions. The
forthcoming EU ETS envisages emissions trading between member states in the EU and at a national level.
When the carbon trading arrangements are put in place and begin to take effect, the embedded
generation owners should be able to participate in the emissions markets within Ireland and the EU and
thereby realise direct financial benefit for any avoided emissions.
However, the emissions benefit may be seen as a mechanism by which the PSO support for the alternative
energy requirements is reduced as the embedded renewable generation plant will be able to source
revenue to support their business from emission trading. This would prevent a windfall crystallising in
favour of the embedded generation plant and serve to reduce the overall cost to the end customers.
Fuel Benefit – the financial value of the fuel benefit is captured within the calculation of the displaced
energy benefit. This benefit does however, provide a step towards improved energy self-sufficiency and
sustainability for Ireland. As such this will present a less exposed position for Ireland in the face of short
term world energy price volatility and increase the overall “value added” within the Irish economy.
Social Benefit – this is a benefit that is very much related to the local community and the employment
opportunities that it may create as a result of the embedded generation construction and operation. It will
be intrinsic to the operating budget structure of the embedded generation. The benefit will flow directly
-195 -
into the local community in the form of wages and no other form of sharing mechanism needs to be put in
place.
9.3.4
Micro- and Small Scale Generation
The very nature of SSEG means that it is connected at LV, typically within domestic or small commercial premises.
The benefits that accrue for larger embedded generators with direct connections to the MV and HV distribution
network will also accrue for SSEG – albeit an order of magnitude lower. However, one of the issues in respect of the
larger embedded generation connections is that it is a point source, whereas the SSEG is likely to be dispersed across
numerous distribution substations along the length of an HV or MV trunk.
To this extent the impact of the SSEG connections is likely to be less sudden and will allow ESB Networks to take
account of it within their LV network designs in a similar way to their projections of load growth that drive the load
related expenditure.
Further, applying the embedded generation connection application process to SSEG generation plant will be a
significant barrier to market entry. It will effectively restrict competition in the supply market and prevent end users
from having a free choice of energy supplier. The connection process for larger embedded generation requires the
parties involved in the transaction to be informed participants with development resource and an understanding of
the mechanisms in place for regulation of the electricity industry.
Given that the expected end user for SSEG will be a typical domestic customer, the position is significantly different.
The product will be sold on the basis of its utility and cost saving potential meaning that, as with consumer goods
and commodities, the transaction process (which will include the electrical connection) will need to be as standard
as possible within the statutory constraints of the distribution licence. Such standardised connection terms could be
applicable for SSEG below a de-minimis level to be determined. These standardised connection terms may provide a
sliding scale of connection charges linked to the generator capacity and incorporating the costs and benefits
associated with typical import/export profiles for this class of customer.
-196 -
9.4
Next Steps
Following the above analysis and suggestions for the Irish market, it is suggested that a number of areas be explored
further.
•
Examine the potential benefits of establishing ‘Active Network Areas’ to provide incentive on the DNO to
partner with embedded generation and/or responsive demand connections to investigate the potential for
alternative voltage control mechanisms;
•
Determine the level of system security support can be attributed to embedded generation, the process to
determine this and the value of the avoided / deferred cost of network capital expenditure;
•
Determine the impact and value of introducing an element of ‘Non-firm’ capacity to the connections for
embedded generators and the operational controls that would need to be implemented to control the
capacity used;
•
Investigate the present costs for islanding schemes and the validity of the ESB Networks prohibition on
establishing islanded portions of the distribution network;
•
Seek to have ESB Networks publish a distribution network statement to provide detailed information on
the development plans for the distribution network and the opportunity areas for generation and/or
demand location. Such a statement would have information relating to network fault statistics, CMLs, in
addition to the capacity available and fault levels on the network;
•
Study into the possibility of establishing an incentive within the ESB Networks regulatory formulae to
incentivise investment in technology and mechanisms that reduce the overall system losses. This should
provide a notional allowable value to losses such that benefit can be derived by ESB where they manage
the network with losses below the target amount.
•
Determine the process to ensure that any deferred capital expenditure or loss benefits are recycled to the
appropriate party and accounted for within the LCTAS connection process or under regular payments;
•
Determine the standard connection terms and costs to facilitate connection of micro- and small-scale
embedded generation to the distribution network;
•
Determine the load profile for a typical SSEG installation associated with domestic, small commercial and
small industrial customer categories. These profiles can then be adopted within the planning process for
new LV networks;
•
Undertake independent assessment will need to be made of the impact on ESB Networks’ operational
costs should elements of the embedded generation calculation methodology be adopted within the
LCTAS connection process;
•
Examine the potential for utilising embedded generation to provide local Ancillary Services within the
distribution system. This would include provision of Black Start, Reactive Compensation Services etc and
would need to determine the technical capability of the technology and the cost of any specific control
equipment necessary to enable the service (both within the DNO and the generator);
-197 -
Appendix A – terms of reference
-198 -
-199 -
-200 -
-201 -
-202 -
-203 -
-204 -
-205 -
APPENDIX B – TOPOGRAPHICAL ANALYSIS
-206 -
B.1
Objectives and Methodology
Topographical analysis was undertaken on a sample of urban, semi-urban and rural distribution networks, identified
as typical, by ESB Networks, the Distribution Network Operator to establish the physical and technical properties that
characterise each network. The objective of this network characterisation was to identify the principal network types
that exist on the Irish electricity distribution system and to use this information to develop representative network
models for use in power system studies. The studies then establish the technical performance of each network and
from the results further analysis was undertaken to turn these figures into actual costs and benefits in monetary
terms.
B.2
Sample of Network Types
The topographical analysis was based on physical data for each network in the sample provided by ESB Networks.
The data included single line diagrams and maps of the network, standard equipment data (i.e. for overhead lines,
cables, transformers and switchgear) and information obtained directly from ESB Networks in discussions with their
system planning engineers.
The results of the analysis of each network, which in every case included more than one primary substation, is
presented in Tables B.1 to B.7. The networks analysed were based in the following areas:
B.3
a)
Trillick (Northern Donegal),
b)
Donegall Town
c)
Arigna (Leitrim)
d)
Tralee (Kerry)
e)
Blake (Kildare)
f)
Inchicore (outskirts of Dublin)
g)
Central Dublin
Network Topography
The results of the analysis of the individual networks have been sorted in Tables B.8, B.9 and B.10 respectively, to
define the characteristics of the sample of rural, semi-urban and dense urban networks.
Table B.8 separates the 10 kV and 20 kV medium voltage networks to identify the specific characteristics at the two
voltage levels.
-207 -
B.4
Derivation of system model
From Tables B.8 to B.10 the characteristics of four representative network models have been derived. The models
specifically relate to:
a)
Rural 10 kV networks
b)
Rural 20 kV networks
c)
Semi-urban 10 kV networks
d)
Dense urban 10 kV networks.
Tables B11 to B.14 present the results of this analysis for the respective network types. The characteristics defined in
these four tables form the basis of the network models described in Section 4 and studied in Section5 of the report.
Although the analysis has principally concentrated on the medium voltage networks Tables B.8 to B.14 include data
for the respective 38 kV networks that supply the medium voltage networks.
-208 -
Table B.1: Topographical analysis of a sample of rural distribution networks TRILLICK area
Feeder lengths
Primary substation and
feeder description
Feeder No.
Resupply feeder
Voltage
(kV)
No. of
boosters
1
Buncrana
10
2
Circuit segment
Nos. of transformers by capacity in kVA
Spur
31Total 3
5
15 25 33 50 100 150 200 400 630 1000
No. phase phase
kVA kVA kVA kVA kVA kVA kVA kVA kVA kVA kVA kVA
(km) (km)
Total
Peak load
capacity
(MW)
(kVA)
No. of
load
points
Ballymacarry
Feeder No. 1 is an
interconnector with
adjacent network
Feeder No. 2 supplies
No. 1
2
-
Trunk
-
Feeder Totals
20
0
local load only
1.5
0
1.5
1.5
0
1.5
0
0
0
0
0
0
0
8
7
Trunk
-
13.1
0
13.1
27
11
Spur
2a
0
5.5
5.5
12
3
Spur
2b
0
6.5
6.5
17
2
Stubs
1-6
4.3
9
13.3
40
9
1
17.4
21
38.4
0
0
96
0
25
9
7
2
Feeder Totals
0
2
2
2
2
6
1
0
0
1
0
6
2
0
0
2200
McCarters
4
2200
1.24
4
3468
60
279
15
321
19
1347
51
5415
1.09
145
Buncrana
Feeder No. 1 supplies
1
-
10
0
local load only
Trunk
-
25.5
2.2
27.7
1
18
51
27
3
5
5
3449
Spur
1a
7
23.1
30.1
2
26
44
16
3
2
1
1874
94
Spur
1b
1.5
4
5.5
5
12
4
1
387
22
Spur
1c
1.7
6
7.7
8
10
3
389
22
Stubs
1 - 13
Feeder Totals
Feeder No. 2 supplies
2
-
20
0
local load only
3
-
20
0
local load only
Feeder No. 4 supplies
local load only
4
-
10
0
15
19.5
50.3
90.5
3
8
40
65
157
6
2
18
1
1
68
8
9
8
4
1
0
Trunk
-
30.4
0
30.4
72
18
Spur
2a
0
5.1
5.1
11
3
Spur
2b
5
0
5
10
1
Spur
2c
0
5.9
5.9
22
2
Stubs
1 - 13
8.1
21.1
29.2
5
71
11
4
3
43.5
32.1
75.6
11
186
0
35
14
7
0
2
15
4
2
Feeder Totals
Feeder No. 3 supplies
4.5
40.2
1
0
Trunk
-
2
6.5
8.5
Stubs
1-3
0
4.6
4.6
Feeder Totals
2
11.1
13.1
Trunk
-
0.2
0
Stubs
1-3
2
0
2
Feeder Totals
2.2
0
2.2
0
-209 -
1584
7
0
0
5
1
1
2
0
1
1
6
2
1
0
7683
24
4
2
115
14
683
14
396
24
2153
95
8030
970
0.2
0
0
0
1
1
1
2
1
2
0
5
0
5
0
0
319
264
1
0
69
2.52
4534
9
2
112
2283
3.0781667
262
835
24
135
9
0.3718333
32
0
0
2283
9
0.71
9
Note: For the purposes of this study a spur is identified as a circuit length equal to 5km or
more (and not dedicated to generator).
Table B.1 (continued): Topographical analysis of a sample of rural distribution networks TRILLICK area (continued)
Feeder lengths
Primary substation and
feeder description
Feeder No.
Resupply
feeder
1
2
Voltage (kV) No. of boosters Circuit segment
Spur No.
3-phase 1-phase
(km)
(km)
Nos. of transformers by capacity in kVA
Total
3 5 kVA 15
kVA
kVA
25
kVA
33 kVA
50
kVA
100
kVA
1
13
1
1
150
kVA
200
kVA
400
kVA
630
kVA
1000
kVA
Total
capacity
(kVA)
Peak
load
(MW)
No. of
load
points
Carndonagh
Feeder No. 1 supplies
10
0
local load only
Trunk
-
13
0
13
1
Spur
1a
7.8
0
7.8
1
Spur
1b
4.2
2.7
6.9
7
10
5
Spur
1c
0
8.3
8.3
2
13
4
Stubs
1-3
Feeder Totals
Feeder No. 2 supplies
2
-
10
1
local load only
3
-
10
0
town load & resupply
Feeder No.4 supplies
4
-
10
0
5.5
41.5
2
7
9
24
72
1
7
5
3
29
8
4
8
-
28.9
4
32.9
39
67
11
3
6.6
4.5
11.1
11
24
12
4
Spur
2b
0
5
5
8
13
1
Spur
2c
0
5
5
10
7
Stubs
1 - 12
4.7
21.9
26.6
30
64
40.2
40.4
80.6
0
98
175
0
0
1
0
1
-
2.5
0
2.5
2.5
0
2.5
Trunk
-
4.9
0
4.9
Spur
4a
2.1
10.4
12.5
Spur
4b
2002
2
2a
Trunk
4
3
Spur
Feeder Totals
local load only
1
12
37
Trunk
Feeder Totals
Feeder No. 3 supplies
4.5
29.5
8
1
13
2
1
37
9
9
1
2
0
1
2
1
5
12
2
3
8
21
11
1
2
4
0
6.9
6.9
8
18
Feeder Totals
7
17.3
24.3
3
21
51
0
Trunk
-
14
0
14
2
23
30
4
Spur
1a
10
12
22
4
25
34
Spur
1b
0
5.5
5.5
1
6
Spur
1c
0
8.8
8.8
Stubs
1-5
0
9.3
9.3
Feeder Totals
24
35.6
59.6
8
Trunk
-
9
0
9
Stubs
1-7
4
6.5
10.5
Feeder Totals
13
6.5
19.5
0
Trunk
-
11.6
0
Spur
3a
0
4
0
0
0
1
0
1
24
337
19
0
5
144
2713
129
1011
51
268
22
155
17
1739
110
329
0
5886
1280
10
0
0
0
1280
10
971
24
927
46
2
2
31
1.06
0
5
0
3788
0
4
17
4
450
951
0
3
2
66
48
0
0
0
442
30
2340
100
Moville
Feeder No. 1 supplies
1
-
10
1
local load only
Feeder No. 2 supplies
2
-
10
0
local load only
Feeder No. 3 supplies
local load only
3
-
10
0
903
60
6
845
69
9
1
201
17
7
13
4
362
24
1
5
24
1
421
31
66
110
0
0
0
0
10
31
27
1
2
2
8
17
11
1
2
4
1
48
0
2
4
0
1
0
11.6
12
29
5
2
3
5
5
4
15
3
7
18
Spur
3b
3.5
2.5
6
Spur
3c
0
6
6
Stubs
1-4
0
10.5
10.5
1
Feeder Totals
15.1
24
39.1
1
36
-210 -
16
38
1
1
6
0
0
0
0
2732
4164
6
201
73
2108
44
1.2
117
2260
57
344
22
8
2
271
18
10
3
249
13
13
22
8
662
44
84
0
1.26
154
21
3
1
0.87
2056
3
0
6
0
0
0
3786
Table B.2: Topographical analysis of a sample of rural distribution networks DONEGAL area
Feeder lengths
Primary substation and feeder
description
Feeder No.
Nos. of transformers by capacity in kVA
Resupply feeder Voltage (kV) No. of boosters Circuit segment Spur 3-phase 1-phase Total 3 kVA 5 kVA 15
25
33
50 100 150 200 400 630
No.
(km)
(km)
kVA kVA kVA kVA kVA kVA kVA kVA kVA
1000
kVA
Total
capacity
(kVA)
Peak load
(MW)
No. of
load
points
Donegal Town
Feeder No. 1 supplies
1
5
10
1 (2x150)
local load only
Trunk
-
11.6
0
11.6
15
59
11
3
Spur
1a
2
15
17
1
19
31
4
1
745
56
Spur
1b
1
39.7
40.7
6
46
82
3
2
1677
139
Stubs
1-4
3.2
5.5
8.7
2
10
32
3
2
2
1735
54
17.8
60.2
78
9
90
204
21
8
10
13.5
0
13.5
13.5
0
13.5
0
Feeder Totals
Feeder No. 2 connects
2
3
10
Trunk
small hydro
Feeder No. 3 connects
-
Feeder Totals
3
2,5
10
2
8
0
0
0
0
0
0
1
1
1
1
1
1
0
3
1
2
1
5
2
0
0
1
1
0
Trunk
-
5.8
0
5.8
2
6
16
Spur
3a
7.7
2
9.7
1
11
29
hydros and supplies
Stubs
1-2
0
6
6
3
7
37
1
local load
Cluster
-
14.9
0.8
15.7
1
15
34
1
3
28.4
8.8
37.2
7
39
116
3
5
5.5
0
5.5
5.5
0
5.5
0
0
0
0
0
0
0
9.5
0
9.5
2
6
28
1
3
2
2
1
2
4
7
3
5
18
25
a cluster of three small
1 (2x100)
2
Feeder Totals
Feeder No.4 connects
4
-
10
windfarm
Feeder No. 5 supplies
local load only
Trunk
-
Feeder Totals
5
1,3
10
Trunk
-
Spur
5a
3
2
5
5b
0
23
23
Spur
5c
5.5
0
5.5
1
4
21
1
Spur
5d
0
6
6
3
18
8
1
Stubs
1
3
0
3
1
13
21
31
52
47
104
-211 -
0
1
1
0
1
1
0
0
9
11
4
1
9
0
0
0
0
0
1
1
1
1
3
8
0
8
0
5
1
104
8260
2.77
353
0
Meenaguse
0
0
0
684
29
943
43
632
48
771
54
3030
0
Spur
Feeder Totals
0
1
1
1
4103
174
Meenadreen
0
0
0
2340
47
4957
28
480
48
471
28
252
30
350
16
8850
197
Table B.3: Topographical analysis of a sample of rural distribution networks ARIGNA area
Feeder lengths
Primary substation
and feeder
description
Arigna
supplies load and
interconnects with
adjacent network
Feeder Resupply feeder Voltage (kV)
No.
2
Other network
No. of
boosters
20
2x100
Circuit
segment
Spur No. 3-phase 1-phase
(km)
(km)
Total
150
kVA
400
kVA
1000
kVA
Peak
load
(MW)
No. of load
points
0
22.1
2
77
2
12
33.5
1
108
7
16
2c
4.8
13.3
18.1
47
1
3
888
51
2d
6.7
15
21.7
1
48
2
1
841
52
3
522
23
1295
81
spur
2
20
spur
2e
6
0
6
2
20
stub
1-7
2
19.3
21.3
56.8
65.9
122.7
4
0
4
0
12.4
1
20
Trunk
-
1
20
Cluster
- 12.4
2
a 18.6
2
a 7.5
spur
spur
Feeder Totals
16.4
12.1
30.7
0
16
4
1
75
5
5
371
0
21
20
32
27
7
12.3
1
20
17
1
3
0
16.4
0
0
0
0
0
-212 -
1
7
0
2
0
2
0
-14.4
4.8
Note: For the purposes of this study a spur is identified as a circuit length equal to 5km or more (and not dedicated to generator).
35
2
Total
capacity
(kVA)
18.3
spur
1
630
kVA
22.1
20
7
200
kVA
15.2
20
10
33 50 kVA 100
kVA
kVA
-
2
2
25
kVA
2b
2
20
15
kVA
spur
20
2
3 kVA 5 kVA
Trunk
2
Feeder Totals
Connectes a cluster of
generators and feeds
into the primary
4 wind farms
connected
Nos. of transformers by capacity in kVA
6
4
0
0
1
0
103
133
10393
1.81
443
0
Arigna
Fuels
1
-14400
1756
2
0
3991
2856
0
0
-14.4
4
Glen
Quarry
97
682
44
-14400
5
Table B.4: Topographical analysis of a sample of rural distribution networks TRALEE area
Feeder lengths
Primary substation and
feeder description
Feeder No.
Resupply feeder
Voltage (kV)
1
-
10
Nos. of transformers by capacity in kVA
No. of boosters Circuit segment Spur
31Total 3
5
15 25 33 50 100 150 200 400 630 1000
No. phase phase
kVA kVA kVA kVA kVA kVA kVA kVA kVA kVA kVA kVA
(km)
(km)
Total
capacity
(kVA)
Peak
load
(MW)
No. of
load
points
Abbeyfeale
Feeder No. 1 supplies
local load only
Trunk
-
20.6
0
20.6
47
Spur
1a
0
7.8
7.8
25
Spur
1b
0
6.5
6.5
20
Spur
1c
4.5
13.5
18
55
Spur
1d
0
9
9
17
Stubs
1 - 13
Feeder Totals
Feeder No. 2 supplies
2
3
10
1 (2x100)
local load only
1 (2x100)
3
2
10
local load only
1 (2x150)
4
-
10
5
-
10
resupply to adjacent fdr
Feeder No. 5 provides
resupply to adjacent fdr
26.3
88.2
2
95
0
0
259
1
2
4
0
9
2
0
1
13.2
0
13.2
44
7
2
1.3
5.5
6.8
26
2
1
Spur
2b
0
9.8
9.8
24
3
Spur
2c
14.6
21.1
35.7
103
8
1
1
1
Spur
2d
0
6.5
6.5
1
15
Stubs
1-4
0
9.3
9.3
1
61
9
1
1
4
29.1
52.2
81.3
15.4
0
15.4
-
2
273
0
57
29
5
2
0
-
1
1354
56
375
25
300
20
991
59
255
17
1557
5
2a
Trunk
1
2
Spur
4
2
0
10
8
5
1
3
7
0
0
1
2
99
0.91
1994
2
3
4832
59
506
29
459
27
2159
114
230
16
2967
0
0
3
276
8315
79
2.49
3685
324
85
Spur
3a
4
5.5
9.5
40
1
983
45
Spur
3b
0
6
6
31
2
531
33
38
3
669
41
31
4
602
36
240
16
654
40
Spur
3c
0
12
12
Spur
3d
0
10.5
10.5
Spur
3e
0
9.5
9.5
16
Spur
3f
0
12
12
37
Stubs
1-5
Feeder Totals
Feeder No. 4 provides
25.1
61.9
3
Trunk
Feeder Totals
Feeder No. 3 supplies
1.2
26.3
3
Trunk
-
Feeder Totals
Trunk
Feeder Totals
-
3.5
9.3
12.8
22.9
64.8
87.7
1.2
0
1.2
1.2
0
1.2
1.6
0
1.6
1.6
0
1.6
-213 -
1
1
1
2
3
3
66
316
5
0
28
4
13
1
8
0
3
1568
3
0
0
1
0
0
0
0
0
1
0
0
0
0
0
79
1.84
50
0
0
0
0
0
0
1
0
8932
0
0
0
1
0
0
375
1
50
1
1400
Kostal
1
1400
1.61
1
Table B.5: Topographical analysis of a sample of rural distribution networks MIDLANDS area
Feeder lengths
Primary substation and feeder
description
Feeder
No.
Resupply
feeder
Voltage
(kV)
No. of
boosters
Circuit
segment
1-phase
(km)
Nos. of transformers by capacity in kVA
Spur
No.
3-phase
(km)
Total
3 kVA 5 kVA
Trunk
-
10.3
0
10.3
1
Spur
1a
0
13.45
13.45
3
15
kVA
25
kVA
33
kVA
50 100 kVA 150
kVA
kVA
200
kVA
2
17
1
9
29
5
3
11
8
1
1
1
1
19
4
4
1
2
2
3
1
400 630 kVA
kVA
1000
kVA
Total
capacity
(kVA)
Peak
load
(MW)
No. of
load
points
Blake
supplies load and
1
interconnects with adjacent
1
network
1
Other network
10
Other network
1
-
2
-
2
Stub
1
0
0
0
Stub
2-6
2.1
8.2
10.3
Feeder Totals
10.3
0
34.05
4
14
57
-
11.95
0
11.95
1
2
13
3
Stub
1
0
0
0
2
-
Stub
2-6
3.25
10.5
13.75
2
1
21
Feeder Totals
supplies load and
3
-
interconnects with adjacent
3
network
10
10
Other network
10.5
25.7
3
3
34
9
3
2
0
6.45
1
4
15
4
5
2
Spur
3a
3.8
3.5
7.3
5
14
5
2
2
12
7
11
41
7
17
Stub
1
0
0
0
-
Stub
2-6
0
4.75
4.75
1 (2x150)
Trunk
10.25
8.25
18.5
-
10.35
0
10.35
1
4
-
Spur
4a
5.6
3.75
9.35
4
-
Spur
4b
2
5
7
2
4
-
Stub
1-7
2.3
11.2
13.5
20.25
19.95
40.2
1
Feeder Totals
-214 -
1
0
0
16
7
6
1
3
22
8
2
2
15
2
1
4
6
19
3
1
6
18
73
19
5
0
2
0
0
0
1
1
6.45
2
10
7
15.2
3
Edenderry 1
1
-
3
4
3
Trunk
Feeder Totals
supplies town load & resupply
3
1141
34
654
46
0
Trunk
supplies town load & resupply
6
2
1
0
1
0
1
0
1
Timahoe
27
3739
1.03
107
724
1
0
0
1944
0
0
0
23
0
0
1487
34
2211
0.73
32
500
26
0
0
421
21
1951
0.81
538
3
3
0
57
1030
79
31
1
909
36
3
1257
28
2
1
6
1
1276
0
0
3980
36
1.56
131
Edenderry
supplies town load & resupply
1
Blake 4
1
-
10
Trunk
-
3.5
0
3.5
6
3
Stub
1
0
1.5
1.5
2
4
3.5
0
5
0
8
7
0
4
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
10
1
2420
13
1
1
1
700
3
4
1
1
1
Feeder Totals
dedicated feeder
2
-
10
Trunk
-
Feeder Totals
supplies town load & resupply
3
4
3
3
10
4
8.5
8.5
3.3
0
3.3
4
Stub
1
1.35
0
1.35
-
Stub
2
0.5
1
1.5
5.15
1
6.15
0
5
2
0
1
0
2
14.95
1
15.95
1
9
16
2
5
2
1
Other network
4
-
network
4
Other network
10
10
-
13
70
-
interconnects with adjacent
4
0
0
207
Trunk
Feeder Totals
supplies load and
8.5
8.5
4
1
0
6
277
??
1000
EuroPeat
1
1000
??
1
368
12
2
0
6
1
1
0
3488
19
8
??
1 (2x100)
Trunk
Spur
4a
1.6
22.3
23.9
2
5
45
7
1
987
60
1 (2x150)
Spur
4b
7.3
19.15
26.45
6
19
45
7
1
1069
78
1x100
23
1
5829
202
198
18
Spur
4c
22.6
59.2
81.8
10
38
120
4
-
Spur
4d
0
7.75
7.75
1
6
11
4
3
Stub
1
1
0
1
3
1
4
3
Stub
2
0
0
0
4
-
Stubs
3-17
4.3
6.85
11.15
2
15
14
1
2
6
2
51.75
116.25
168
22
95
252
3
45
11
7
Feeder Totals
Note: For the purposes of this study a spur is identified as a circuit length equal to 5km or more (and not dedicated to generator).
-215 -
4
2
3
2933
24
1
1
0
5
2
13
6
44
63
5
0
0
2682
1
1
13761
49
??
456
Table B.6: Topographical analysis of a sample of semi-urban distribution networks INCHICORE area (Dublin outskirts)
Feeder lengths
Primary substation and
feeder description
Feeder No.
Resupply
feeder
Voltage
(kV)
1
2
10
No. of
boosters
Nos. of transformers by capacity in kVA
Circuit
segment
Spur No.
3-phase 1-phase Total
(km)
(km)
Trunk
-
1.09
0
1.09
Feeder Totals
1.09
0
1.09
3 kVA 5 kVA
15
kVA
25
kVA
33
kVA
50
kVA
100
kVA
150
kVA
200
kVA
400
kVA
630
kVA
1000
kVA
Total
capacity
(kVA)
Peak load
No. of
(MW)
load points
2
2
2
4060
0
0
0
0
0
0
0
2
2
2
4060
3
3
3090
6
1
1
1
1600
3
1
4
3
1
4690
1
8
1
Ballymount
supplies town load & resupply
supplies town load & resupply
2
supplies town load & resupply
2
supplies town load & resupply
3
supplies town load & resupply
3
supplies town load & resupply
3
resupply only
3
Semperit 12
10
1
Inchicore
Central 6
10
Trunk
-
1.78
0
1.78
Stub
1
1.4
0
1.4
Feeder Totals
3.18
0
3.18
Trunk
-
3.9
0
3.9
2 and 5
Stub
1
1.23
0
1.23
4
Stub
2
0.17
0
0.17
Stub
3
0
0
0
5.3
0
5.3
3.53
0
3.53
Clondalkin 4
Feeder Totals
supplies town load & resupply
4
supplies town load & resupply
4
supplies town load & resupply
supplies load and
interconnects with adjacent
network
supplies load and
interconnects with adjacent
network
supplies local load only
5
Clondalkin 4
10
3
3
10
Trunk
-
Stub
1
0.29
0
0.29
Feeder Totals
3.82
0
3.82
Trunk
-
1.25
0
1.25
2.44
0
2.44
5
unknown
Stub
1
5
unknown
Stub
2
0.52
0
0.52
Feeder Totals
4.21
0
4.21
6
-
10
Trunk
-
0.84
0
0.84
Feeder Totals
0.84
0
0.84
-216 -
0
0
0
0
0
0
0
0
0
0
1
1
1
2
1
6
0.83
2.1
0
1
0
0
1
1
0
11
515
4
630
1
3
8
2
0
5225
1
3
2
2
4660
1
3
3
2
5290
1
2
1
1
1
0
0
0
0
0
0
0
0
1
2
0
0
0
0
0
0
1
0
2
5
0
0
0
0
0
0
0
0
0
0
0
0.81
16
8
630
3
9
4080
0
0
6
1
1.32
9
1000
3
2590
6
800
3
0
4390
2
1
2260
2
1
2260
2
2.29
11
3
0.33
3
Clondalkin
supplies town load & resupply
1
2
10
10
Trunk
0
-
2.82
0
2.82
Feeder Totals
2.82
0
2.82
supplies town load & resupply
2
4
Trunk
-
4.13
0
4.13
resupply only
supplies load and
interconnects with adjacent
network
2
1
Stub
3
0
0
0
2
Other
network
Stub
4a
1.74
0
1.74
resupply only
2
Ballymount 4
Stub
4b
0.4
0
0.4
supplies town load & resupply
2
Semperit 11
Stub
5
0.58
0
0.58
Stubs
1-2
0.44
0
0.44
Feeder Totals
7.29
0
7.29
Trunk
-
5.72
0
5.72
Stub
1
1.25
0
1.25
-
Stub
2
0.37
0
0.37
Ballymount 4
Stub
3
0.4
0
0.4
7.74
0
7.74
supplies town load & resupply
3
Ballymount 3
supplies town load & resupply
3
Semperit 11
local load only
3
supplies town load & resupply
3
10
0
Feeder Totals
supplies load and
interconnects with adjacent
network
4
local load only
4
resupply only
4
local load only
4
local load only
4
Other
network
Trunk
-
4.76
0
4.76
Stub
1
0.1
0
0.1
Stub
2
1.6
0
1.6
-
Stub
3
0.46
0
0.46
-
Stub
4
Semperit 11
10
Feeder Totals
0.3
0
0.3
7.22
0
7.22
-217 -
0
0
0
0
0
0
0
0
1
3
3
0
3
3
0
3090
3
3
2
1
4160
10
0
0
3200
10
0
0
1
400
1
1
500
2
4
1
0
0
0
0
0
0
2
0
6
7
11
2
1
3
3
1
0
0
0
0
0
0
0
0
1
3090
1
1
0
0
0
0
0
0
1
23
3290
7
1400
2
630
1
1
1
1030
2
5
5
1
6350
6
5
1
6550
1
1
7
7
1
0
3.59
6
1
1
0
8260
6
1.31
1.89
12
200
1
0
0
1030
2
630
1
12
8410
1
3.4
16
Table B.6 (continued): Topographical analysis of a sample of semi-urban distribution networks INCHICORE area (Dublin outskirts) continued
Feeder lengths
Primary substation and feeder
description
Feeder Resupply
No.
feeder
Voltage No. of
Circuit Spur No. 3-phase
(kV)
boosters segment
(km)
1-phase
(km)
Nos. of transformers by capacity in kVA
Total
3 kVA 5 kVA
15
kVA
25
kVA
33
kVA
50
kVA
100
kVA
150
kVA
200
kVA
400
kVA
630
kVA
1000
kVA
Total
capacity
(kVA)
Peak load No. of
(MW)
load
points
Semperit
supplies load and interconnects with
adjacent network
1
supplies local load only
1
supplies local load only
1
interconnects with adjacent network
1
supplies town load & resupply
2
supplies local load only
2
resupply only
2
supplies local load only
supplies load and interconnects with
adjacent network
supplies load and interconnects with
adjacent network
2
2
2
supplies local load only
3
supplies local load only
3
resupply
3
Other
network
10
Other
network
Inchicore
Central 1
10
Inchicore
Central 2
Other
network
Other
network
-
10
Inchicore
Central 7
Trunk
-
4.1
0
4.1
2
7
4
5720
Stub
1
3.2
0
3.2
3
3
3
3690
9
Stub
2
0.34
0
0.34
400
1
Stub
3
0.26
0
0.26
Feeder Totals
7.9
0
7.9
supplies town load & resupply
4
supplies local load only
4
resupply
4
10
Inchicore
Central 2
5
-
10
supplies local load only
6
-
10
supplies no load
7
-
10
0
0
0
0
0
0
0
5
11
7
6
1
-
3.32
0
3.32
2
Stub
1
0.23
0
0.23
1
Stub
2
0
0
0
Stub
3
0.34
0
0.34
Stub
4
0.79
0
0.79
Stub
5
0.46
0
0.46
Feeder Totals
5.14
0
5.14
Trunk
-
1.83
0
1.83
Stub
1
0.18
0
0.18
Stub
2
0
0
0
2.01
0
2.01
Trunk
-
2.59
0
2.59
Stub
1
0.1
0
0.1
Stub
2
Feeder Totals
supplies local load only
0
0
Trunk
Feeder Totals
Inchicore
Central
direct
1
Trunk
0.1
0
0.1
2.79
0
2.79
-
1.17
0
1.17
Feeder Totals
1.17
0
1.17
0.5
0
0.5
Trunk
-
Feeder Totals
0.5
0
0.5
-
0.63
0
0.63
Feeder Totals
0.63
0
0.63
Trunk
-218 -
13
1
1
2
0
0
1
0
0
0
1
1
1
1
0
0
9810
0
3.01
3430
9
200
1
0
0
1
515
3
1
800
3
1
2
6
10
1
1000
2
2
2
0
1
5945
3
2
0
0
0
1
1
1
0
2
1
3
2
2
2
0
1
9
400
1
3043
0
1.79
0
0
0
0
0
0
0
1
3
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
5
400
1
0
2660
2
2000
2
2000
0
0
1.32
0
0
0
0
0
0
0
0
0
0
0
6
2
0
0.02
John Player
MV
1
0
??
1
0
0
10
2260
0
0
19
2643
0
0
23
0
2
0
??
0
Table B.6 (continued): Topographical analysis of a sample of semi-urban distribution networks INCHICORE area (Dublin outskirts) continued
Feeder lengths
Primary substation and feeder
description
supplies town load & resupply
resupply
Feeder Resupply
No.
feeder
8
9
Voltage No. of
Circuit Spur No. 3-phase
(kV)
boosters segment
(km)
10
11
supplies town load & resupply
10
9
resupply
10
8
Trunk
10
10
supplies town load & resupply
11
supplies town load & resupply
11
supplies town load & resupply
11
resupply
11
10
-
1.31
0
1.31
1.31
0
1.31
Trunk
-
0.5
0
0.5
Feeder Totals
0.5
0
0.5
Trunk
-
5.99
0
5.99
Stub
1
0
0
0
5.99
0
5.99
15
kVA
25
kVA
33
kVA
50
kVA
100
kVA
150
kVA
200
kVA
400
kVA
630
kVA
1000
kVA
2
2000
0
0
0
0
0
0
0
0
0
2
2000
0
0
0
0
0
0
0
0
0
0
0
0
0
4
7
5
11010
16
0
0
0
0
0
0
0
0
0
0
0
4
1.46
Stub
1
0.71
0
0.71
1
Stub
2
0.5
0
0.5
2
Stub
3
0
0
0
2.67
12
supplies local load only
12
resupply
12
resupply
12
supplies local load only
12
-
Stub
4
0.4
0
0.4
supplies local load only
12
Stub
5
0.14
0
0.14
resupply
12
Ballymount
2
Stub
6
2
2.86
2
??
0
0
0
0
Peak load No. of
(MW)
load
points
0
1.46
2.67
Total
capacity
(kVA)
0
-
supplies local load only
Inchicore
Central 4
Inchicore
Central 6
3 kVA 5 kVA
Trunk
Feeder Totals
-
Nos. of transformers by capacity in kVA
Total
Feeder Totals
Feeder Totals
Clondalkin
3
Clondalkin
4
Inchicore
Central 5
Clondalkin
2
1-phase
(km)
7
5
1
0
11010
0.5
16
0
Bailey MV
0
1030
2
800
2
0
0
0
0
0
0
0
0
0
0
1830
0
0
3
1
2.57
2
2
1
1830
5
4
1
630
1
Trunk
-
3.46
0
3.46
Stub
1
0.3
0
0.3
Stub
2
0
0
0
0
0
Stub
3
0
0
0
0
0
Feeder Totals
0
0
0
4.3
0
4.3
-219 -
1
1
400
1
1
1100
2
1
3960
0
0
0
0
0
0
0
1
0
2
3
2
0
1.94
9
Table B.6 (continued): Topographical analysis of a sample of semi-urban distribution networks INCHICORE area (Dublin outskirts) continued
Feeder lengths
Primary substation and feeder description Feeder
No.
Resupply
feeder
Voltage
No. of
(kV)
boosters
Circuit
segment
Spur 3-phase 1-phase
No.
(km)
(km)
Total
Nos. of transformers by capacity in kVA
3 kVA 5 kVA
15
kVA
25
kVA
33
kVA
50
kVA
100
kVA
150
kVA
200
kVA
400
kVA
630
kVA
6
4
1000
kVA
Total
capacity
(kVA)
Peak
load
(MW)
No. of
load
points
Inchicore Central
supplies town load & resupply
1
supplies local load only
1
Semperit 2
10
-
supplies town load & resupply
2
Semperit 2
resupply
2
Semperit 4
10
Trunk
-
4.76
0
4.76
2
Stub
1
1.53
0
1.53
5
Feeder Totals
6.29
0
6.29
Trunk
-
4.03
0
4.03
Stub
1
0
0
0
4.03
0
4.03
Feeder Totals
supplies load and interconnects
with adjacent network
3
supplies town load & resupply
4
supplies town load & resupply
4
supplies local load only
Other network
Semperit 12
10
6
4
5
Clondalkin 4
resupply
5
Semperit 11
supplies town load & resupply
6
Ballymount 3
resupply
6
Semperit 12
resupply
6
6
Trunk
-
1.83
0
1.83
Feeder Totals
1.83
0
1.83
Trunk
-
3.82
0
3.82
Stub
1
0.4
0
0.4
Stub
supplies town load & resupply
supplies local load only
10
4
-
10
10
2
0.37
0
0.37
Feeder Totals
4.59
0
4.59
Trunk
-
2.37
0
2.37
Stub
0
0
0
0
0
0
0
0
1
5320
12
1000
7
6
4
0
6320
3
4
1
1
3930
5
??
10
0
0
0
0
0
0
0
1
0
3
4
0
0
0
0
0
0
0
0
0
2
1
1
0
0
800
1
2030
2
2
0
0
0
0
0
0
0
0
2
0
??
10
??
2
800
8
2
1
1
9
3930
3
2
4860
1
17
12
3
0
Kylemore
Tranction
1
6890
??
16
0
0
1
0.34
0
0.34
Feeder Totals
2.71
0
2.71
Trunk
-
3.32
0
3.32
1200
4
Stub
1
0
0
0
0
0
Stub
2
0.14
0
0.14
0
3
0.2
0
0.2
Feeder Totals
Stub
3.66
0
3.66
0
0
0
0
0
Note: For the purposes of this study a spur is identified as a circuit length equal to 5km or more (and not dedicated to generator).
-220 -
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2
2
2
2
0
0
0
0
0
0
??
0
0
0
Truck
Centre
MV
1
1200
??
5
Table B.7 : Topographical analysis of a sample of dense urban distribution networks CENTRAL DUBLIN AREA
Primary substation and feeder Feeder
description
No.
Resupply
feeder
Voltage No. of
Circuit Spur
(kV)
boosters segment No.
Nos. of transformers by capacity in kVA
Feeder lengths
31Total 3 kVA 5
15
25
33
50 100 150 200 400
phase phase
kVA kVA kVA kVA kVA kVA kVA kVA kVA
(km)
(km)
630
kVA
1000
kVA
Total
Peak load
capacity
(MW)
(kVA)
No. of
load
points
Morrowbone Lane
resupply
1
Guinness and
10
Watling St 1
supplies load and interconnects with
adjacent network
supplies load and interconnects with
adjacent network
2
3
Other network
Other network
10
10
Trunk
-
1
0
1
Feeder Totals
1
0
1
Trunk
-
0.73
0
0.73
Feeder Totals
0.73
0
0.73
Trunk
-
1.72
0
1.72
Feeder Totals
1.72
0
1.72
supplies town load, resupply &
4
Newmarket
10
Trunk
-
1.79
0
1.79
interconnects with adjacent
4
Other network
10
Stub
1
0
0
0
1.79
0
1.79
1.4
0
1.4
network
Feeder Totals
-
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
3
1
2
0
0
0
0
0
0
0
0
0
1
2
0
5
1
0
0
0
0
1200
0.37
3
0
0
1200
0.37
3
1660
0.93
4
1660
0.93
4
4150
2.26
3
??
0
0
0
0
0
0
0
0
0
0
0
5
1
4150
0
6
0
2.26
St James'
Hospital
supplies town load & resupply
5
Kingsbridge
10
Trunk
1.4
0
1.4
0
0
0
supplies town load & resupply
6
Newmarket
10
Trunk
-
1.94
0
1.94
8
1
6040
9
local load only
6
10
Stub
1
0.27
0
0.27
1
630
1
Feeder Totals
resupply
7
10
Trunk
Feeder Totals
resupply
8
-
Newmarket
Newmarket
10
2.21
0
2.21
-
0
0
0
Feeder Totals
0
0
0
Trunk
-
0
0
0
Feeder Totals
0
0
0
-
0.1
0
0.1
Feeder Totals
0
6
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
9
1
6670
??
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
2.93
10
??
0
??
0
0
0
0
Watling Street
0
Guinness
supplies town load & resupply
1
resupply
2
supplies town load & resupply
1
3
M'bone Lane 1
Kingsbridge
Kingsbridge
10
Trunk
10
Trunk
10
0.1
0
0.1
-
0
0
0
Feeder Totals
0
0
0
Trunk
-
2.32
0
2.32
Feeder Totals
2.32
0
2.32
supplies town load & resupply
4
Wolfetone St
10
Trunk
-
1.68
0
1.68
resupply
4
Kingsbridge
10
Stub
1
0
0
0
1.68
0
1.68
supplies town load & resupply
5
Phibsborough
10
Trunk
2.065
0
2.065
Feeder Totals
-
-221 -
0
0
0
0
0
0
0
0
0
0
0
0
0
-2.53
0
-2.53
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
0
0
0
0
0
??
0
1
6
2
6180
3.79
9
1
6
2
6180
3.79
9
2
4
2
5320
1.85
8
2
4
2
5320
1.85
8
1
7
2
6810
0.4
10
resupply
5
Phibsborough
10
Stub
1
Feeder Totals
0.2
0
0.2
2.265
0
2.265
Note: For the purposes of this study a spur is identified as a circuit length equal to 5km or more (and
not dedicated to generator).
-222 -
1
0
0
0
0
0
0
0
0
0
1
8
2
6810
0.4
11
Table B.8: Topographical analysis of a sample of rural distribution networks (i.e. 10 kV and 20
Area
Primary
substations
(Network)
Voltage Capacit
(kV)
y (MVA)
2003
2003 Area of Max Load Feeder Installed Peak Voltage No. of No. No. No. of Length Length
of of Spur
Peak Valley supply Density
Case capacity load
(kV) feeders of of clusters
spurs stubs
Trunk ccts
Demand Demand (km2) (kW/km2)
(kVA) (MW)
ccts
(km)
(MW)
(MW)
(km)
North
Donegal
Ballymacarry Pry 38/20/10
Buncrana Pry
1x5
1.09
0.30
38
10kV cct ignored because it is a dedicated feeder
38/20/10
2x5
6.68
1.71
171
Carndonagh Pry
28.7
39.1
1x2, 1x5
4.39
1.26
141
31.1
2x5
3.11
0.94
116
26.8
38/10
Moville Pry
South
Donegal
Donegal Town
Pry
38/10
38/10
2x5
6.89
1.99
205
33.6
173
10.5
* excludes two feeders directly connecting EG to primary
Leitrim
Kerry
Kildare
Arigna BSP
110/20
1x15
1.81
1.01
Shortest
Longest
Total
Shortest
Longest
Total
Shortest
Longest
Total
Shortest
Longest
2200
5415
7615
2283
7683
18966
1280
5886
13294
4164
2732
1.24
1.09
2.33
0.71
2.52
6.68
0.42
1.94
4.39
1.2
0.87
10
20
10/20
10
10
10/20
10
10
10
10
10
1
4
4
-
2
2
0
3
8
0
3
8
0
3
6
6
3
13
32
0
12
15
7
5
0
0
0
0
0
0
0
0
0
0
13.1
13.1
0.2
27.7
66.8
2.5
32.9
53.3
9
14
12
12
0
43.3
71.3
0
21.1
63.5
0
36.3
13.3
13.3
2
19.5
68.6
0
26.6
32.1
10.5
9.3
0
0
0
0
0
0
0
0
0
0
38.4
38.4
2.2
90.5
206.7
2.5
80.6
148.9
19.5
59.6
0
0
0
0
1
1
0
1
Total
10682
3.11
10
3
6
16
0
34.6
53.3
30.3
0
118.2
1
Shortest
Longest
3030
8260
1.04
2.83
10
10
-
1
2
2
4
1
0
5.8
11.6
9.7
57.7
6
8.7
15.7
0
37.2
78
1
1
Total*
20140
6.89
10
3
7
7
1
26.9
106.9
17.7
15.7
167.2
2
10393
1.81
20
-
4
7
0
22.1
79.3
21.3
0
122.7
10393
1.81
20
1
4
7
0
22.1
79.3
21.3
0
122.7
8315
4832
2.49
0.91
10
10
-
4
4
1
13
0
0
13.2
20.6
58.8
41.3
9.3
26.3
0
0
81.3
88.2
2
0
Total**
22079
5.24
10
3
14
22
0
49.2
159.6
48.4
0
257.2
3
Shortest
Longest
Total***
Shortest
Longest
277
13761
17516
1951
3980
0.17
8.43
10.73
0.81
1.56
10
10
10
10
10
3
-
0
4
4
1
2
1
17
20
6
7
0
0
0
0
0
3.5
16
22.8
6.5
10.4
0
139.9
139.9
7.3
16.3
1.5
12.2
16.5
4.8
13.5
0
0
0
0
0
5
168.1
179.3
18.6
40.2
0
3
3
0
2
Total***
10881
4.13
10
4
4
25
0
39.1
37.1
42.3
0
118.5
2
Shortest
Longest
Total***
*
**** only one feeder supplying load, the other links to a cluster of generators
Abbeyfeale
38/10
2x5
6.85
2.59
295
23.2
Shortest
Pry
Longest
** excludes re-supply with no gens or load connected
Edenderry
Pry
38/20/10
2x5
10.73
3.09
128
83.8
*** excludes feeder directly connecting EG to primary
Blake Pry
38/20/10
2x5
4.13
1.46
77
53.6
Length Length Total
No of
of stub
of
feeder Booster
ccts cluster length
Tx's
(km)
ccts
(km)
(km)
-223 -
Table B8 (Cont’d)
Notes: Estimated values
Lowest
1.81
1.01
173
10.5
Shortest 23500 8.08
Total
7
6
20
1
40.7 75.8 34.1 15.7 166.3
-
1
3
0
5.8
(shown in purple) assumed
when not provided
Analysis
of
Total
Sample
density
Average 3357
Average 5.08
1.59
149
34.0
density
Highest 10.73
Lowest
of
10 kV
Sample
3.09
128
83.8
6.85
2.59
295
23.2
density
Average 5.63
1.74
150
37.7
3.09
128
83.8
density
Lowest
of
1.81
1.01
173
10.5
density
Average 2.08
20 kV
density
Sample
Highest
density
0.72
99
21.0
1.71
171
39.1
23.8
1
327.9 722.9 290.5 15.7 1357.1
6
0
12.6 27.8 11.2
0.6
52.2
Longest 62942 21.96 Total
9
27
84
0
168.4 447.2 150.7
0
766.3
Average 6994
-
3
9
0
18.7 49.7 16.7
0.0
85.1
7
6
20
1
40.7 75.8 34.1 15.7 166.3
3
-
1
3
0
5.8
2.44 Average
Shortest 23500 8.08
All
Total
1.15 Average
106758 38.96 Total
46 121
1
4.9
2.2
23.8
0
253.8 603.6 208.8
16
1082
12
-
2
6
0
11.5 27.4
0.7
49.2
1
7
21
71
0
133.2 355.9 116.1
0
605.2
8
Average 6733
2.72 Average
-
3
10
0
19.0 50.8 16.6
0
86.5
1
Shortest 5415
1.09
1
2
6
0
13.10
12
13.30 0.00 38.40
Average 5415
1.09 Average
-
2
6
0
13.10
12
13.30 0.00 38.40
4
11
29
0
74.1 119.3 81.7
0
All
1.77 Average
22
10.8
Longest 47134 19.06 Total
24808 6.35
Average 6202
6.68
2.2
2
Average 4853
Highest 10.73
4.9
57 150
1.74 Average
26
10.8
-
Average 3357
density
Analysis
131566 45.31 Total
Average 5060
density
Analysis
All
1.15 Average
Total
Total
1.59 Average
Longest 10393 1.81
Total
Average 10393 1.81 Average
-224 -
9.5
275.1
-
3
7
0
18.5 29.8 20.4
0.0
68.8
1
4
7
0
22.1 79.3 21.3
0
122.7
-
4
7
0
22.1 79.3
0
123
21
Table B 9: Topographical analysis of a sample of semi-urban distribution networks
Area
Primary
Voltage
substations
(kV)
Capacity 2003 Peak
(MVA)
(Network)
2003
Area of Max Load
Demand
Valley
supply
Density
(MW)
Demand
(km2)
(kW/km2)
Feeder
Case
Installed Peak
capacity
load
(kVA)
(MW)
Voltage
(kV)
No. of No. of No. of No. of
Length Length Length Length Total
feeders spurs stubs clusters of Trunk of Spur of stub
(MW)
ccts
ccts
ccts
(km)
(km)
(km)
of
feeder
cluster length
ccts
(km)
(km)
Inchicore Ballymount
Clondalkin
Semperit
38/10
38/10
38/10
2x10
2x10
3x10
7.73
10.19
16.03
3.27
2.991636
3.8
2.00
3.00
5.00
3865.0
3396.7
3206.0
Shortest
2260
0.33
10
-
0
0
0
0.84
0
0
0
0.84
Longest
5225
0.81
10
-
0
2
0
3.9
0
1.4
0
5.3
Total
25915
7.73
10
6
0
6
0
12.39
0
6.05
0
18.44
Shortest
3090
1.31
10
-
0
0
0
2.82
0
0
0
2.82
Longest
6350
1.89
10
-
0
3
0
5.72
0
2.02
0
7.74
Total
26110
10.19
10
4
0
10
0
17.43
0
7.64
0
25.07
Shortest
2000
2.86
10
-
0
0
0
1.17
0
0
0
1.17
Longest
9810
3.01
10
-
0
2
0
4.1
0
3.54
0
7.64
Total
42258
16.03
10
9
0
13
0
25.23
0
7.79
0
33.02
Shortest
800
0.27
10
-
0
0
0
1.83
0
0
0
1.83
Longest
6320
2.13
10
-
0
1
0
4.76
0
1.53
0
6.29
** - excluding feeder to John Player (unknown
load)
Inchicore
Central
38/10
1x10
Lowest
Analysis
density
of
Highest
Total
density
Sample
Average
6.45
6.45
1.93
1.93
3.00
3
2150.0
2150
Total
19140
6.45
10
5
0
4
0
17.76
0
2.64
0
20.4
Shortest
8150
4.77
Total
4
0
0
0
6.66
0
0
0
6.66
Average
2038
1.19
Average
-
0
0
0
1.7
0.0
0.0
0.0
1.7
Longest
27705
7.84
Total
4
0
8
0
18.48
0
8.49
0
26.97
Average
6926
1.96
Average
-
0
2
0
4.6
0.0
2.1
0.0
6.7
Total
113423
40.40
Total
24
0
33
0
72.81
0
24.12
0
96.93
Average
4726
1.68
Average
-
0
1
0
3.0
0.0
1.0
0.0
4.0
3396.6666
16.03
10.10
2.991636
3.00
3
3
67
3154.4
density
Notes: Estimated values (shown in purple) assumed when not provided
Table B 10: Topographical analysis of a sample of dense urban distribution networks
-225 -
Area
Primary
substations
Voltage Capacity 2003 Peak 2003
(kV)
(MVA)
(Network)
Demand
(MW)
Valley
Area of Max Load
supply
Density
Feeder
Installed
Case
Demand (km2) (kW/km2)
Peak
Voltage
capacity
load
(kV)
(kVA)
(MW)
No. of No. of No. of No. of
Length Length Length Length Total
feeders spurs stubs clusters of Trunk of Spur of stub
(MW)
ccts
ccts
ccts
(km)
(km)
(km)
of
feeder
cluster length
ccts
(km)
(km)
Dublin
Marrowbone
Central
Lane
38/10
Watling Street 38/10
1x15
1x10
6.5
3.81
3.19
1.97
0.765
0.625
8497
6096
Shortest
1200
0.37
10
-
0
0
0
0.73
0
0
0
0.73
Longest
6670
2.93
10
-
0
1
0
1.94
0
0.27
0
2.21
Total
31990
6.5
10
5
0
1
0
7.58
0
0.27
0
7.85
Shortest
5320
1.85
10
-
0
0
0
1.68
0
0
0
1.68
Longest
6180
3.79
10
-
0
0
0
2.32
0
0
0
2.32
Total*
18310
3.81
10
3
0
0
0
6.165
0
0
0
6.165
* - Excludes the Guinness
connections
Lowest
3.81
1.97
0.625
6096
Analysis density
of
Highest
Total
density
Sample Average
density
6.5
1.15
3.19
0.57
0.765
0.15
8497
1621
Shortest
6520
2.22
Total
2
0
0
0
2.41
0
0
0
2.41
Average
3260
1.11
Average
-
0
0
0
1.2
0.0
0.0
0.0
1.2
Longest
12850
6.72
Total
2
0
1
0
4.26
0
0.27
0
4.53
Average
6425
3.36
Average
-
0
1
0
2.1
0.0
0.1
0.0
2.3
Total
50300
10.31
Total
8
0
1
0
13.745
0
0.27
0
14.015
Average
6288
1.29
Average
-
0
0
0
1.7
0.0
0.0
0.0
1.8
-226 -
Table B11 - Rural 10 kV networks
Feeder No.
Ballymacarry
Trunk (km)
Spurs (km)
Stub (km)
3-ph
1-ph
3-ph
1-ph
3-ph
1-ph
1.5
0
0
0
0
0
25.5
2.2
10.2
33.1
4.5
15
4
0.2
0
0
0
2
0
1
13
0
12
11
4.5
1
2
28.9
4
6.6
14.5
4.7
21.9
3
2.5
0
0
0
0
0
4
4.9
0
2.1
17.3
0
0
1
2
Buncrana
1
2
3
Carndonagh
Moville
Donegal Town
Arigna
1
14
0
10
26.3
0
9.3
2
9
0
0
0
4
6.5
3
11.6
0
3.5
13.5
0
10.5
1
11.6
0
3
54.7
3.2
5.5
3
5.8
0
7.7
2
0
6
5
9.5
0
8.5
31
3
0
1
2
Abbeyfeale
Edenderry
Blake
1
20.6
0
4.5
36.8
1.2
25.1
2
13.2
0
15.9
42.9
0
9.3
3
15.4
0
4
55.5
3.5
9.3
1
3.5
0
0
0
0
1.5
3
3.3
0
0
0
1.9
1
4
15.0
1
31.5
108.4
5.3
6.9
1
10.3
0
0
13.5
2.1
8.2
2
12.0
0
0
0
3.3
10.5
3
6.5
0
3.8
3.5
0
4.8
4
10.4
0
7.6
8.8
2.3
11.2
Total (km)
246.5
7.2
130.9
472.7
45.4
163.4
%
97.2
2.8
21.7
78.3
21.7
78.3
-227 -
Table B12 - Rural 20 kV networks
Feeder No.
3-ph
Ballymacarry
Buncrana
Carndonagh
Moville
Donegal Town
Arigna
Abbeyfeale
Edenderry
Blake
1
2
1
2
3
4
1
2
3
4
1
2
3
1
3
5
1
2
1
2
3
1
3
4
1
2
3
4
Total (km)
%
Trunk (km)
1-ph
Spurs (km)
Stub (km)
3-ph
1-ph
3-ph
1-ph
13.1
0
0
12
4.3
9
30.4
2
0
6.5
5
0
11
0
8.1
0
21.1
4.6
4
22.1
0
0
26.1
32.7
16.9
46.6
0
2
0
19.3
71.6
91.7
6.5
8.3
63.8
42.4
86.5
57.6
14.4
21.1
54
78.9
-228 -
Table B 13 - Semi-urban 10 kV networks
Feeder No.
Ballymount
Clondalkin
Semperit
Inchicore Central
Trunk (km)
Spurs (km)
Stub (km)
3-ph
1-ph
3-ph
1-ph
3-ph
1-ph
1
1.09
0
0
0
0
0
2
1.78
0
0
0
1.4
0
3
3.9
0
0
0
1.4
0
4
3.53
0
0
0
0.29
0
5
1.25
0
0
0
2.96
0
6
0.84
0
0
0
0
0
1
2.82
0
0
0
0
0
2
4.13
0
0
0
3.16
0
3
5.72
0
0
0
2.02
0
4
4.76
0
0
0
2.46
0
1
4.1
0
0
0
3.8
0
2
3.32
0
0
0
1.82
0
3
1.83
0
0
0
0.18
0
4
2.59
0
0
0
0.2
0
5
1.17
0
0
0
0
0
6
0.5
0
0
0
0
0
8
1.31
0
0
0
0
0
10
5.99
0
0
0
0
0
11
1.46
0
0
0
1.21
0
12
3.46
0
0
0
0.84
0
1
4.76
0
0
0
1.53
0
2
4.03
0
0
0
0
0
3
1.83
0
0
0
0
0
4
3.82
0
0
0
0.77
0
5
2.37
0
0
0
0.34
0
6
3.32
0
0
0
0.34
0
Total (km)
75.68
0
0
0
24.72
0
%
100.0
0.0
-
-
100.0
0.0
-229 -
Table B 14 - Dense urban 10 kV networks
Feeder No.
Marrowbone Lane
Watling Street
Trunk (km)
Spurs (km)
Stub (km)
3-ph
1-ph
3-ph
1-ph
3-ph
1-ph
2
0.73
0
0
0
0
0
3
1.72
0
0
0
0
0
4
1.79
0
0
0
0
0
5
1.4
0
0
0
0
0
6
1.94
0
0
0
0.27
0
1
0.1
0
0
0
0
0
3
2.32
0
0
0
0
0
4
1.68
0
0
0
0
0
5
2.07
0
0
0
0.2
0
Total (km)
13.745
0
0
0
0.47
0
%
100.0
0.0
-
-
100.0
0.0
-230 -
Table B.15: Summary of Principal Model Characteristics for each Medium Voltage Network Type
Rural 10 kV circuits
Parameter
Rural 20 kV circuits
Semi-urban 10 kV circuits
Dense urban 10 kV circuits
Shortest
Average
Longest
Shortest
Average
Longest
Shortest
Average
Longest
Shortest
Average
Longest
1.41
1.40
1.42
1.50
1.68
1.67
0.42
0.43
0.42
0.40
0.34
0.36
Trunk sections
4
8
13
8
10
11
4
7
11
3
5
6
Trunk boosters
0
0
2
0
0
0
0
0
0
0
0
0
Trunk section loads (MW)
0.108
0.083
0.078
0.07
0.082
0.085
0.298
0.176
0.131
0.37
0.258
0.534
Total Trunk length (km)
5.64
11.2
18.46
12
16.835
18.37
1.68
3.01
4.62
1.2
1.7
2.16
Total trunk load (MW)
0.432
0.664
1.014
0.56
0.82
0.935
1.192
1.232
1.441
1.11
1.29
3.204
1
2
3
2
3
4
0
0
0
0
0
0
2.35
2.98
3.68
1.8
3.02
6.02
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Spur loads (MW)
0.417
0.32
0.328
0.155
0.151
0.129
0
0
0
0
0
0
Total Spur length (km)
2.35
5.96
11.04
3.6
9.06
24.08
0
0
0
0
0
0
Total Spur load (MW)
0.417
0.64
0.984
0.31
0.453
0.516
0
0
0
0
0
0
3
6
10
6
7
7
0
1
2
0
0
1
Stub length (km)
0.35
0.34
0.36
0.5
0.612
0.63
0
1.01
1.06
0
0
0.14
Stub loads (MW)
0.099
0.076
0.07
0.036
0.045
0.051
0
0.448
0.261
0
0
0.157
Total Stub length (km)
1.05
2.04
3.6
3
4.284
4.41
0
1.01
2.12
0
0
0.14
Total Stub load (MW)
0.297
0.456
0.7
0.216
0.315
0.357
0
0.448
0.522
0
0
0.157
Total circuit length (km)
9.04
19.2
33.1
18.6
30.179
46.86
1.68
4.02
6.74
1.2
1.7
2.3
Total load (MW)
1.146
1.76
2.698
1.086
1.588
1.808
1.192
1.68
1.963
1.11
1.29
3.361
Trunk section length (km)
No. of spurs
Spur length (km)
Spur boosters
No. of stubs
-231 -
Appendix C – Network Studies
-232 -
C.1
Power system studies of representative 110/38/10 kV rural network
Tables C.1.1 to C.1.3 present a summary of the significant results of power system studies of the 110/38/10 kV rural
network, including power flows, power losses, voltage profiles, circuit utilisation and fault levels, for the 1 MW
embedded generation case.
Tables C.1.4 to C.1.6 present the corresponding results for the 2.5 MW embedded generation case and Tables C.1.7 to
C.1.9 the results for the 5 MW generation case.
Table C1.1 – 1MW; 10 kV Rural Network; Shortest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
202
204
208
Generator Size
-
1
1
Reactive Power ( kVAr)
1
1
1
328
328
328
Total Losses - kW
744.3
731.8
743.4
703
705.7
702.5
Total Losses - kVAr
804.6
709.2
728.6
687
692
690
Sending Voltage - (200)
1.024
1.027
1.027
1.027
1.027
1.027
Endpoint Voltage - (207)
0.984
0.987
0.987
1.014
1.038
1.026
Fault level - HV (38kV) - (100) - Amps
1280
1359
1352.8
1351
1245
1343
Fault level - MV (10kV) - Sending (200) - Amps
3104
3439
3411.7
3404
3379
3370
Fault level - MV (10kV) - Ending (207) - Amps
859
822.3
880
976
1125
1037
Transformer flow - kW
3045
2539
2545
2508
2526
2524
Transformer flow - kVAr
1279
1071
1080
1045
1062
1061
Power leaving MV Prim - kW
1180
1180
1180
136
154
151
Power leaving MV Prim - kVAr
395
395
395
11
52
50
Load levels - kW
1.14
1.14
1.14
1.14
1.14
1.14
0.375
0.375
0.375
0.375
0.375
0.375
2
3
4
5
6
Load levels - kVAr
Loading Matrix
Study Number
Section
1
Tx
63
52
53
52
52
52
A
32
32
32
3
4
4
B
26
26
26
2
1
2
C
20
20
20
20
7
7
D
6
6
6
6
21
6
E
12
11
11
11
11
16
Voltage Bus
1
2
3
4
5
6
200
1.024
1.027
1.027
1.027
1.027
1.027
201
1.009
1.012
1.012
1.026
1.025
1.025
202
0.997
1
1
1.027
1.026
1.026
203
0.987
0.991
0.991
1.017
1.029
1.029
203.5
0.979
0.982
0.982
1.009
1.02
1.041
204
0.985
0.988
0.988
1.015
1.039
1.026
205
0.984
0.987
0.987
1.014
1.038
1.026
-233 -
Table C 1.2 – 1MW; 10 kV Rural Network; Average Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
234
246
238
Generator Size
-
1
1
1
1
1
Reactive Power ( kVAr)
330
330
330
Total Losses - kW
744.3
731.8
743.4
636
634.3
640
Total Losses - kVAr
804.6
709.2
728.6
646.8
645.4
649
Sending Voltage - (200)
1.024
1.027
1.027
1.027
1.027
1.027
Endpoint Voltage - (238)
0.927
0.93
0.93
0.985
1.011
1.035
Fault level - HV (38kV) - (100) - Amps
1280
1359
1352.8
1341
1330.6
1331
Fault level - MV (10kV) - Sending (200) - Amps
3104
3439
3411.7
3363
3316.7
3318
Fault level - MV (10kV) - Ending (238) - Amps
522.5
531.2
530
625
700.6
820
Transformer flow - kW
3045
2539
2545
2491
2485
2489
Transformer flow - kVAr
1279
1071
1080
1039
1035
1038
Power leaving MV Prim - kW
1801
1800
1800
706
696
704
624
623
623
242
234
239
Power leaving MV Prim - kVAr
Load levels - kW
Load levels - kVAr
1.68
1.68
1.68
1.68
1.68
1.68
0.553
0.553
0.553
0.553
0.553
0.553
2
3
4
5
6
Loading Matrix
Study Number
Section
1
Tx
63
52
53
51
51
51
A
49
49
49
19
19
19
B
44
44
44
15
14
14
C
40
39
39
10
10
10
D
29
28
28
1
1
1
E
24
24
24
22
5
5
F
19
19
19
18
10
10
G
7
7
7
7
7
20
H
9
9
9
8
19
8
2
2
2
2
2
25
I
Voltage Bus
1
2
3
4
5
6
230
1.024
1.027
1.027
1.027
1.027
1.027
231
1.001
1.005
1.004
1.019
1.019
1.019
232
0.981
0.985
0.984
1.012
1.012
1.012
233
0.963
0.967
0.966
1.007
1.008
1.007
234
0.95
0.954
0.954
1.008
1.008
1.008
235
0.94
0.943
0.943
0.997
1.011
1.01
236
0.931
0.935
0.934
0.989
1.015
1.014
236.5
0.923
0.926
0.926
0.982
1.033
1.007
237
0.928
0.931
0.931
0.986
1.012
1.024
238
0.927
0.93
0.93
0.985
1.011
1.035
-234 -
Table C 1.3 1MW; 10kV Rural Network; Longest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
266
273
286
Generator Size
-
1
1
1
1
1
330
330
330
Setting of booster ( 263)
setting of booster ( 267)
Reactive Power ( kVAr)
Total Losses - kW
744.3
731.8
743.4
418
316
321
Total Losses - kVAr
804.6
709.2
728.6
411
346
350
Sending Voltage - (200)
1.024
1.027
1.027
1.016
1.016
1.016
Endpoint Voltage - (283)
0.983
0.987
0.986
0.993
0.995
0.995
Fault level - HV (38kV) - (100) - Amps
1280
1359
1352.8
1321
1305
1303
Fault level - MV (10kV) - Sending (200) - Amps
3104
3439
3411.7
3298
3234
3225
Fault level - MV (10kV) - Ending (283) - Amps
293.4
297
296.6
366
569
515
Transformer flow - kW
3045
2539
2545
2373
2328
2331
Transformer flow - kVAr
1279
1071
1080
915
886
889
Power leaving MV Prim - kW
3091
3085
3086
1752
1661
1668
Power leaving MV Prim - kVAr
1249
1244
1244
629
579
583
Load levels - kW
2.52
2.52
2.52
2.52
2.52
2.52
Load levels - kVAr
0.83
0.83
0.83
0.83
0.83
0.83
1
2
4
5
6
Loading Matrix
Study Number
Section
3
Tx
63
52
53
48
47
47
A
85
85
85
48
45
46
B
81
81
81
44
41
42
C
77
77
77
40
38
38
D
93
92
92
36
33.6
34
E
55
55
55
25
22
23
F
51
51
51
21
18
19
G
47
46
47
47
14
14
H
81
80
80
43
10
10
I
27
27
27
31
1
1
J
23
23
23
26
6
6
K
19
19
19
22
10
10
L
15
15
15
17
14
14
M
4
4
4
5
25
4
N
9
9
9
10
9
20
-235 -
Table C 1.3 (cont’d)
Voltage Bus
1
2
3
4
5
6
260
1.024
1.027
1.027
1.016
1.016
1.016
261
0.984
0.987
0.987
0.994
0.995
0.995
262
0.945
0.949
0.949
0.973
0.976
0.976
263
0.909
0.913
0.913
0.954
0.959
0.958
264
0.969
0.974
0.973
0.937
0.943
0.943
265
0.944
0.948
0.948
0.926
0.933
0.932
266
0.92
0.925
0.924
0.916
0.924
0.923
267
0.898
0.903
0.903
0.894
0.918
0.917
268
0.975
0.98
0.98
0.874
0.913
0.912
269
0.962
0.967
0.967
0.86
0.914
0.913
270
0.951
0.957
0.956
0.847
0.916
0.915
271
0.942
0.948
0.947
0.837
0.921
0.92
272
0.935
0.941
0.94
0.829
0.927
0.926
272.5
0.924
0.93
0.93
0.817
0.916
0.951
273
0.933
0.939
0.938
0.827
0.939
0.924
274
0.983
0.987
0.986
0.993
0.995
0.995
Table C 1.4 – 2.5MW; 10 kV Rural Network; Shortest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
202
204
208
Generator Size
-
2.5
2.5
Reactive Power ( kVAr)
Total Losses - kW
744.3
730
780
2.5
2.5
2.5
315
-937
-1091
754
915
964
Total Losses - kVAr
804.6
610
725
639
794
834
Sending Voltage - (200)
1.024
1.025
1.024
1.021
1.011
1.011
Endpoint Voltage - (207)
0.984
0.985
0.985
1.038
1.049
1.049
Fault level - HV (38kV) - (100) - Amps
1280
1464
1433
1434
1407
1399
Fault level - MV (20kV) - Sending (200) - Amps
3104
3949
3789
3776
3611
3568
Fault level - MV (20kV) - Ending (207) - Amps
859
906
896
1133
1520
1225
Transformer flow - kW
3045
1788
1822
1800
1880
1905
Transformer flow - kVAr
1279
775
829
1042
1746
1842
Power leaving MV Prim - kW
1180
1180
1180
-1306
-1174
-1130
Power leaving MV Prim - kVAr
395
395
395
88
1415
1593
Load levels - kW
1.14
1.14
1.14
1.14
1.14
1.14
0.375
0.375
0.375
0.375
0.375
0.375
Load levels - kVAr
-236 -
Loading Matrix
Study Number
Section
1
2
3
4
5
6
Tx
63
37
38
40
49
50
A
32
32
32
34
48
51
B
26
26
26
39
50
53
C
20
20
20
19
53
55
D
6
6
6
6
62
6
E
12
11
11
11
11
61
Voltage Bus
1
2
3
4
200
1.024
1.025
1.024
1.021
5
1.011
6
1.011
201
1.009
1.01
1.009
1.034
1.015
1.015
202
0.997
0.998
0.997
1.05
1.022
1.022
203
0.987
0.989
0.988
1.041
1.033
1.033
203.5
0.979
0.98
0.979
1.033
1.024
1.024
204
0.985
0.986
0.985
1.039
1.05
1.05
205
0.984
0.985
0.985
1.038
1.049
1.049
Table C 1.5 2.5MW; 10 kV Rural Network; Average Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
234
246
238
Generator Size
-
2.5
2.5
Reactive Power ( kVAr)
2.5
2.5
2.5
-50.6
-1092
-1117
Total Losses - kW
744.3
730
780
699
1028
1043
Total Losses - kVAr
804.6
610
725
617
876
887
Sending Voltage - (200)
1.024
1.025
1.024
1.018
1.009
1.009
Endpoint Voltage - (238)
0.927
0.928
0.927
1.029
1.016
1.05
Fault level - HV (110kV) - (100) - Amps
1280
1464
1433
1401
1363
1363
Fault level - MV (20kV) - Sending (200) - Amps
3104
3949
3789
3611
3410
3411
Fault level - MV (20kV) - Ending (238) - Amps
522.5
539
535
758
883
1287
Transformer flow - kW
3045
1788
1822
1773
1936
1944
Transformer flow - kVAr
1279
775
829
1214
1863
1882
Power leaving MV Prim - kW
1801
1801
1801
-745
-444
-428
Power leaving MV Prim - kVAr
624
624
624
648
1860
1893
Load levels - kW
1.68
1.68
1.68
1.68
1.68
1.68
0.553
0.553
0.553
0.553
0.553
0.553
Load levels - kVAr
-237 -
Loading Matrix
Study Number
Section
1
2
3
4
5
6
Tx
63
37
38
41
51
51
A
49
49
49
25
50
50
B
44
44
44
28
50
50
C
40
39
39
31
50
51
D
29
28
29
39
53
53
E
24
24
24
21
55
55
F
19
19
19
17
57
57
G
7
7
7
7
7
64
H
9
9
9
8
62
8
I
2
2
2
2
2
67
Voltage Bus
1
2
3
4
5
6
230
1.024
1.025
1.024
1.018
1.009
1.009
231
1.001
1.003
1.002
1.022
1.003
1.002
232
0.981
0.982
0.982
1.029
0.999
0.998
233
0.963
0.965
0.964
1.037
0.998
0.997
234
0.95
0.952
0.951
1.05
1.003
1.001
235
0.94
0.941
0.94
1.04
1.01
1.008
236
0.931
0.932
0.931
1.033
1.02
1.018
236.5
0.923
0.924
0.923
1.025
1.05
1.01
237
0.928
0.929
0.928
1.03
1.017
1.032
238
0.927
0.928
0.927
1.029
1.016
1.05
Table C 1.6 2.5MW; 10kV Rural Network; Longest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
266
273
286
Generator Size
-
2.5
2.5
2.5
2.5
2.5
822
-451
-577
Reactive Power ( kVAr)
Total Losses - kW
744.3
730
780
264
Total Losses - kVAr
804.6
610
725
224
436
523
Sending Voltage - (200)
1.024 1.025 1.024 1.021
1.011
1.009
Endpoint Voltage - (283)
0.983 0.984 0.984 1.019
0.997
0.993
Fault level - HV (110kV) - (100) - Amps
1280
1464
1433
1360
1319
1314
Fault level - MV (20kV) - Sending (200) - Amps
3104
3949
3789
3474
3265
3241
Fault level - MV (20kV) - Ending (283) - Amps
293.4
299
298
471
1060
778
Transformer flow - kW
3045
1788
1822
1555
1687
1750
Transformer flow - kVAr
1279
775
829
579
1315
1420
Power leaving MV Prim - kW
3091
3089
3090
122
380
506
Power leaving MV Prim - kVAr
1249
1247
1248
63
1484
1679
-238 -
553
682
Load levels - kW
2.52
2.52
2.52
2.52
2.52
2.52
Load levels - kVAr
0.83
0.83
0.83
0.83
0.83
0.83
1
2
3
4
Loading Matrix
Study Number
Section
5
6
Tx
63
37
38
32
41
43
A
85
85
85
4
40
46
B
81
81
81
1
38
44
C
77
77
77
4
36
42
D
93
93
93
7.9
35.4
40.6
E
55
55
55
18
35
39
F
51
51
51
22
35
39
G
47
47
47
41
36
39
H
81
81
81
36.9
37.9
40.6
I
27
27
27
27
44
45
J
23
23
23
23
46
48
K
19
19
19
19
49
50
L
15
15
15
15
52
53
M
4
4
4
4
60
4
N
9
9
9
9
8
58
-239 -
Table C1.6 (cont’d)
Voltage Bus
1
2
3
4
5
6
260
1.024
1.025
1.024
1.021
1.011
1.009
261
0.984
0.985
0.984
1.02
0.998
0.994
262
0.945
0.947
0.946
1.02
0.987
0.98
263
0.909
0.91
0.91
1.021
0.978
0.969
264
0.969
0.971
0.97
1.025
0.971
0.959
265
0.944
0.945
0.944
1.033
0.969
0.955
266
0.92
0.922
0.92
1.043
0.969
0.954
267
0.898
0.9
0.899
1.025
0.972
0.954
268
0.975
0.977
0.975
1.007
0.977
0.957
269
0.962
0.964
0.962
0.995
0.986
0.965
270
0.951
0.953
0.952
0.985
0.998
0.975
271
0.942
0.944
0.943
0.976
1.013
0.988
272
0.935
0.937
0.935
0.969
1.029
1.003
272.5
0.924
0.926
0.925
0.959
1.019
1.05
273
0.933
0.935
0.934
0.967
1.05
1.001
274
0.983
0.984
0.984
1.019
0.997
0.993
Table C1.7 - 5MW; 10kV Rural Network; Shortest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
202
204
208
Generator Size
-
5
5
5
5
5
-1844
-2420
-2420
Reactive Power ( kVAr)
Total Losses - kW
744.3
722
965.4
1185
1691
1811
Total Losses - kVAr
804.6
514
915.8
932
1286
1358
Sending Voltage - (200)
1.024
1.026
1.029
0.997
0.998
0.997
Endpoint Voltage - (207)
0.984
0.986
0.99
1.038
1.085
1.046
Fault level - HV (38kV) - (100) - Amps
1280
1614
1522
1523
1455
1438
Fault level - MV (20kV) - Sending (200) - Amps
3104
4801
4240
4130
3757
3677
Fault level - MV (20kV) - Ending (207) - Amps
859
938
915
1311
2251
1458
Transformer flow - kW
3045
534
656
768
999
1040
Transformer flow - kVAr
1279
309
513
2269
2718
2727
Power leaving MV Prim - kW
1180
1180
1180
-3516
-2963
-2862
395
395
395
2455
3273
3283
Power leaving MV Prim - kVAr
Load levels - kW
Load levels - kVAr
-240 -
1.14
1.14
1.14
1.14
1.14
1.14
0.375
0.375
0.375
0.375
0.375
0.375
Loading Matrix
Study Number
Section
1
2
3
4
5
6
Tx
63
12
16
45
55.000
56
A
32
32
32
110
116
114
B
26
26
26
114
118
117
C
20
20
20
19
121
119
D
6
6
6
6
129
5
12
11
11
11
11
124
E
Voltage Bus
1
2
3
4
5
6
200
1.024
1.026
1.029
201
1.009
1.011
1.015
0.997
0.998
0.997
1.01
1.022
1.009
202
0.997
0.999
1.003
1.05
1.029
1.027
203
0.987
0.99
0.993
1.041
1.053
1.049
203.5
204
0.979
0.981
0.984
1.033
1.045
1.097
0.985
0.987
0.991
1.039
1.085
1.046
205
0.984
0.986
0.99
1.038
1.085
1.046
Table C 1.8 - 5MW; 10kV Rural Network; Average Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
234
246
238
Generator Size
-
5
5
5
5
5
-2420
-2420
-2420
reactive power from generator
Total Losses - kW
744.3
722
965.4
1539
2391
2445
Total Losses - kVAr
804.6
514
915.8
1199
1729
1779
Sending Voltage - (200)
1.024
1.026
1.029
0.991
0.995
0.993
Endpoint Voltage - (238)
0.927
0.929
0.933
1.028
1.044
1.102
Fault level - HV (110kV) - (100) - Amps
1280
1614
1522
1448
1378
1380
Fault level - MV (20kV) - Sending (200) - Amps
3104
4801
4240
3737
3413
3417
Fault level - MV (20kV) - Ending (238) - Amps
522.5
549
542.5
887
1083
2209
Transformer flow - kW
3045
534
656
941
1306
1384
Transformer flow - kVAr
1279
309
513
2687
2891
2972
Power leaving MV Prim - kW
1801
1801
1800
-2479
-1702
-1589
624
623
623
3450
3801
3950
Power leaving MV Prim - kVAr
Load levels - kW
Load levels - kVAr
1.68
1.68
1.68
1.68
1.68
1.68
0.553
0.553
0.553
0.553
0.553
0.553
-241 -
Loading Matrix
Study Number
Section
1
2
3
4
5
6
Tx
63
12
16
54
60
62
A
49
49
49
112
110
112
B
44
44
44
114
111
113
C
40
39
39
116
112
114
D
29
28
28
122
116
117
E
24
24
24
21
118
119
F
19
19
19
17
120
121
G
7
7
7
7
7
127
H
9
9
9
8
125
8
I
2
2
2
2
2
130
Voltage Bus
1
2
3
4
5
6
230
1.024
1.026
1.029
0.991
0.995
0.993
231
1.001
1.004
1.007
0.998
0.991
0.988
232
0.981
0.984
0.987
1.01
0.992
0.987
233
0.963
0.966
0.969
1.026
0.997
0.991
234
0.95
0.953
0.956
1.05
1.01
1.003
235
0.94
0.942
0.946
1.04
1.027
1.02
236
0.931
0.933
0.937
1.032
1.048
1.041
236.5
0.923
0.925
0.929
1.025
1.109
1.033
237
0.928
0.93
0.934
1.029
1.045
1.069
238
0.927
0.929
0.933
1.028
1.044
1.102
Table C 1.9 - 5MW; 10kV Rural Network; Longest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
266
273
286
Generator Size
-
5
5
5
5
5
-1772
-1824
-1679
1126
2838
3231
Reactive power
Total Losses - kW
744.3
722 965.4
Total Losses - kVAr
804.6
514 915.8
778
1876
2124
Sending Voltage - (200)
1.024 1.026 1.029
0.999
0.99
0.989
Endpoint Voltage - (283)
0.983 0.986 0.989
0.997
0.963
0.958
Fault level - HV (110kV) - (100) - Amps
1280
1614
1522
1385
1325
1319
Fault level - MV (20kV) - Sending (200) - Amps
3104
4801
4240
3493
3219
3195
Fault level - MV (20kV) - Ending (283) - Amps
293.4 302.7
301
533
1795
944
Transformer flow - kW
3045
656
719
1592
1789
Transformer flow - kVAr
1279
309
513
2169
2730
2782
Power leaving MV Prim - kW
3091
3086
3080 -1529
173
564
Power leaving MV Prim - kVAr
1249
1245
1241
4155
4232
-242 -
534
3161
Load levels - kW
2.52
2.52
2.52
2.52
2.52
2.52
Load levels - kVAr
0.83
0.83
0.83
0.83
0.83
0.83
1
2
3
4
Loading Matrix
Study Number
Section
5
6
Tx
63
12
16
43
60
63
A
85
85
85
92
110
113
B
81
81
81
93
109
112
C
77
77
77
94
108
110
D
93
93
92
95
108
110
E
55
55
54
99
108
108
F
51
51
50
101
108
108
G
47
47
46
40
109
109
H
81
81
80
37
111
110
I
27
27
27
26
115
114
J
23
23
23
22
118
116
K
19
19
19
19
120
119
L
15
15
15
4
130
4
M
4
4
4
9
8
125
N
9
9
9
3
2
3
-243 -
Table C1.9 (cont’d)
Voltage Bus
1
2
3
4
5
6
260
1.024
1.026
1.029
0.999
0.99
0.989
261
0.984
0.986
0.99
0.997
0.964
0.958
262
0.945
0.948
0.952
0.999
0.941
0.931
263
0.909
0.912
0.916
1.005
0.923
0.907
264
0.969
0.972
0.977
1.014
0.909
0.889
265
0.944
0.947
0.952
1.03
0.904
0.878
266
0.92
0.923
0.928
1.05
0.903
0.872
267
0.898
0.901
0.907
1.031
0.907
0.872
268
0.975
0.979
0.984
1.014
0.916
0.876
269
0.962
0.966
0.972
1.002
0.933
0.89
270
0.951
0.955
0.961
0.992
0.955
0.908
271
0.942
0.946
0.952
0.983
0.981
0.931
272
0.935
0.939
0.945
0.976
1.012
0.959
272.5 ( 286)
0.924
0.928
0.934
0.966
1.002
1.05
273
0.933
0.937
0.943
0.974
1.05
0.957
274 (283)
0.983
0.986
0.989
0.997
0.963
0.958
-244 -
C.2
Power system studies of representative 110/38/20 kV rural network
Tables C.2.1 to C.2.3 present a summary of the significant results of power system studies of the 110/38/20 kV rural
network, including power flows, power losses, voltage profiles, circuit utilisation and fault levels, for the 1 MW
embedded generation case.
Tables C.2.4 to C.2.6 present the corresponding results for the 2.5 MW embedded generation case and Tables C.2.7 to
C.2.9 the results for the 5 MW generation case.
Table C2.1 - 1MW; 20kV Rural Network; Shortest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
204
218
208
Generator Size
-
1
1
1
1
1
Total Losses - kW
11.1
9.9
12.87
2.55
7.8
7
Total Losses - kVAr
24.7
5.5
10.23
1.45
2.9
4
Sending Voltage - (200)
1.012
1.011
1.011
0.999
0.994
0.988
Endpoint Voltage - (208)
0.998
0.998
0.997
0.997
0.997
0.998
Fault level - HV (38kV) - (100) - Amps
2676
2751
2748
2746
2743
2742
Fault level - MV (20kV) - Sending (200) - Amps
1440
1608
1604
1591
1580
1575
Fault level - MV (20kV) - Ending (208) - Amps
748
786
785
829
858
890
Transformer flow - kW
1097
96
99.1
88.5
93.8
93.3
383
34.8
39.5
30.7
32
33.2
1096
1096
1096
88.5
93.8
93.2
Transformer flow - kVAr
Power leaving MV Prim - kW
Power leaving MV Prim - kVAr
363
363
363
30.5
31.9
33.1
Load levels - kW
1.09
1.09
1.09
1.09
1.09
1.09
Load levels - kVAr
0.36
0.36
0.36
0.36
0.36
0.36
Loading Matrix
Study Number
Section
1
2
3
4
5
6
Tx
22.1
1.9
2
1.8
A
11.4
11.4
11.4
0.9
1
1
B
13.5
13.5
13.5
0.2
0.2
0.2
C
12.1
12.1
12.1
1.7
1.6
1.7
D
9
9
9
4.8
4.8
4.8
E
7.5
7.5
7.5
7.5
6.2
6.3
F
6.1
6.1
6.1
6.1
7.7
7.8
G
2.9
2.9
2.9
2.9
2.9
10.9
H
1.5
1.5
1.5
1.5
1.5
12.4
P
0.7
0.7
0.7
0.7
0.7
0.7
-245 -
1.9
1.9
Voltage Bus
1
2
3
4
5
6
200
1.012
1.011
1.011
0.999
0.994
0.988
201
1.011
1.01
1.01
0.999
0.993
0.988
202
1.007
1.007
1.007
0.999
0.993
0.988
203
1.005
1.004
1.004
1
0.994
0.988
204
1.002
1.002
1.002
1.001
0.995
0.989
205
1
1
1
0.999
0.997
0.993
206
0.999
0.999
0.999
0.998
0.998
0.991
206.5
1.005
207
0.998
0.998
0.998
0.997
0.998
0.995
208
0.998
0.998
0.997
0.997
0.997
0.998
Table C2.2 - 1MW; 20kV Rural Network; Average Feeder Studies
Study Number
Generator Position
Generator Size
1
2
3
4
5
6
-
200
299
263
272
270
-
1
1
1
1
1
32.85
30.4
40.2
15.4
13.88
8.12
Total Losses - kVAr
58.2
22.5
33.5
14
10.6
9.75
Sending Voltage - (200)
1.02
1.026
1.002
1.026
1.021
1.02
Total Losses - kW
Endpoint Voltage - (270)
0.99
0.996
0.97
1.005
1.011
1.025
Fault level - HV (110kV) - (100) - Amps
2896
2792
2967
2969
2964
2962
Fault level - MV (20kV) - Sending (200) - Amps
1483
1658
1634
1651
1635
1629
Fault level - MV (20kV) - Ending (270) - Amps
Transformer flow - kW
Transformer flow - kVAr
Power leaving MV Prim - kW
607
633.1
620
658.5
695
760
1621
618
708
603
602
596
583
219
231
210
207
206
1618
1618
1768
603
602
595
Power leaving MV Prim - kVAr
542
542
547
204
201
200
Load levels - kW
1.59
1.59
1.59
1.59
1.59
1.59
0.523
0.523
0.523
0.523
0.523
0.523
Load levels - kVAr
-246 -
Loading Matrix
Study Number
Section
1
2
3
4
5
Tx
32.8
12.5
14.2
12.2
12.1
6
12
A
16.6
16.5
18.4
6.2
6.2
6.1
B
20.2
20.1
22.1
6.4
6.4
6.4
C
18.5
18.4
20.2
4.7
4.7
4.6
D
15.3
15.2
16.7
15.1
1.5
1.5
E
13.6
13.5
14.8
13.4
0.2
0.3
F
11.8
11.7
12.8
11.6
1.9
2
G
8.6
8.5
9.3
8.4
8.4
5.2
H
6.8
6.8
7.4
6.7
6.7
6.9
I
5
5
5.5
5
4.9
8.6
J
1.8
1.8
1.9
1.7
1.7
11.8
K
3.1
3
3.5
3
16.6
3
Voltage Bus
1
2
3
4
5
6
260
1.02
1.026
1.002
1.026
1.021
1.02
261
1.018
1.024
1
1.025
1.02
1.019
262
1.013
1.019
0.994
1.024
1.019
1.017
263
1.008
1.014
0.989
1.022
1.017
1.016
264
1.003
1.009
0.984
1.018
1.017
1.016
265
1
1.006
0.98
1.014
1.017
1.016
266
0.996
1.003
0.977
1.011
1.017
1.016
267
0.994
1
0.974
1.009
1.015
1.018
268
0.992
0.998
0.972
1.007
1.013
1.02
269
0.991
0.997
0.971
1.006
1.012
1.022
270
0.99
0.996
0.97
1.005
1.011
1.025
0.974
1.009
1.028
1.014
266.5
272
0.995
-247 -
Table C 2.3 - 1MW; 20kV Network; Longest Feeder
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
233
245
241
Generator Size
-
1
1
1
1
1
43.71
42.4
45.3
24
69.8
32.8
37.5
Total Losses - kW
Total Losses - kVAr
25.7
11.1
22.3
18
14.6
Sending Voltage - (200)
1.014 1.019 1.019 1.019
1.019
1.019
Endpoint Voltage - (253)
0.978 0.983 0.983 0.992
1.007
1.022
Fault level - HV (110kV) - (100) - Amps
5359
5367
5367
5367
5367
5366
Fault level - MV (20kV) - Sending (200) - Amps
4122
4307
4303
4299
4279
4280
Fault level - MV (20kV) - Ending (253) - Amps
658.5
664
663
681
725
789
Transformer flow - kW
1852
851
853
833
834
819
Transformer flow - kVAR
665
299
304
288
284
281
1851
1850
1850
833
834
819
Power leaving MV Prim - kVAr
618
618
618
279
275
272
Load levels - kW
1.81
1.81
1.81
1.81
1.81
1.81
0.595 0.595 0.595 0.595
0.595
0.595
Power leaving MV Prim - kW
Load levels - kVAr
Loading Matrix
Study Number
Section
1
Tx
2
3
4
5
6
13
6
6
5.8
5.8
5.7
A
19.1
19.1
19.1
8.6
8.6
8.4
B
23.4
23.2
23.2
9.4
9.4
9.3
C
20.4
20.3
20.3
6.5
6.5
6.3
D
18.5
18.5
18.5
18.3
4.7
4.5
E
15.6
15.5
15.5
15.4
1.8
1.6
F
13.7
13.6
13.6
13.5
0.1
0.3
G
11.8
11.7
11.7
11.6
1.9
2.1
H
8.8
8.7
8.7
8.6
8.5
5.1
I
6.9
6.8
6.8
6.8
6.7
6.9
J
3.8
3.8
3.8
3.8
3.7
9.8
K
1.9
1.9
1.9
1.9
1.9
11.7
L
2.6
2.6
2.6
2.6
17
2.6
-248 -
Table C2.3 (Cont’d)
Voltage Bus
1
2
3
4
5
6
230
1.014
1.019
1.019
1.019
1.019
1.019
231
1.012
1.017
1.016
1.018
1.018
1.018
232
1.006
1.011
1.011
1.016
1.016
1.016
233
1
1.005
1.005
1.014
1.014
1.014
234
0.995
1
1
1.009
1.013
1.013
235
0.991
0.996
0.996
1.005
1.012
1.012
236
0.987
0.992
0.992
1.001
1.012
1.012
237
0.984
0.989
0.989
0.998
1.013
1.013
238
0.982
0.986
0.986
0.995
1.01
1.014
239
0.98
0.985
0.985
0.994
1.008
1.016
240
0.979
0.984
0.983
0.992
1.007
1.019
241
0.978
0.983
0.983
0.992
1.007
1.022
253
0.978
0.983
0.983
0.992
1.007
1.022
237.5
1.034
Table C 2.4 - 2.5MW; 20kV Rural Network; Shortest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
204
218
208
Generator Size
-
2.5
2.5
2.5
2.5
2.5
Total Losses - kW
11.1
11.7
30
32
91.8
86.8
Total Losses - kVAr
24.7
36.8
64.7
49
66.8
78.2
Sending Voltage - (200)
1.012
1.014
1.013
0.984
0.98
0.97
Endpoint Voltage - (208)
0.998
1
1
0.998
1.009
1.017
Fault level - HV (38kV) - (100) - Amps
2676
2843
2835
2822
2809
2805
Fault level - MV (20kV) - Sending (200) - Amps
1440
1864
1840
1797
1754
1741
Fault level - MV (20kV) - Ending (208) - Amps
Transformer flow - kW
Transformer flow - kVAr
Power leaving MV Prim - kW
748
836
830
940
1026.8
1133
1097
-1402
-1384
-1382
-1322
-1327
383
-425
-397
-413
-393
-384
1096
1096
1096
-1384
-1324
-1329
Power leaving MV Prim - kVAr
363
363
363
-445
-423
-414
Load levels - kW
1.09
1.09
1.09
1.09
1.09
1.09
Load levels - kVAr
0.36
0.36
0.36
0.36
0.36
0.36
-249 -
Loading Matrix
Study Number
Section
1
2
3
4
5
6
Tx
22.1
27.9
27.4
27.5
26.3
26.3
A
11.4
11.3
11.3
14.7
11.4
14.3
B
13.5
13.5
13.5
20.9
20.4
20.3
C
12.1
12.1
12.1
22.3
21.6
21.8
D
9
9
9
25.5
24.7
25
E
7.5
7.5
7.5
7.5
26.2
26.5
F
6.1
6
6
6
27.7
27.9
G
2.9
2.9
2.9
2.9
2.9
31.1
H
1.5
1.5
1.5
1.5
1.5
31.5
P
0.7
0.7
0.7
0.7
0.7
0.7
Voltage Bus
1
2
3
4
200
1.012
1.014
1.013
0.984
0.98
0.97
201
1.011
1.013
1.012
0.986
0.981
0.972
202
1.007
1.009
1.009
0.991
0.986
0.977
203
1.005
1.006
1.006
0.996
0.991
0.982
204
1.002
1.004
1.004
1.003
0.997
0.988
205
1
1.002
1.002
1.001
1.003
0.995
206
0.999
1.001
1.001
0.999
1.01
1.002
206.5
0.998
207
0.998
1
1
0.999
1.01
1.009
208
0.998
1
1
0.998
1.009
1.017
-250 -
5
6
Table C2.5 - 2.5MW; 20kV Rural Network; Average Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
263
272
270
Generator Size
-
2.5
2.5
2.5
2.5
2.5
Total Losses - kW
32.8
30.5
45.8
22.8
100.7
92.4
Total Losses - kVAr
58.2
28.4
53.2
24.6
48.2
63.2
Sending Voltage - (200)
1.02
1.029
1.054
1.019
0.977
0.97
Endpoint Voltage - (270)
0.99
1
1.016
1.011
0.996
1.027
Fault level - HV (38kV) - (100) - Amps
2896
3064
3065
3052
3021
3014
Fault level - MV (20kV) - Sending (200) - Amps
1483
1917
1919
1875
1763
1741
Fault level - MV (20kV) - Ending (270) - Amps
Transformer flow - kW
Transformer flow - kVAr
Power leaving MV Prim - kW
607
663.4
674
719
789
985
1620
-882
-866
-890
-812
-820
583
-267
-242
-270
-247
-232
1618
1618
1616
-890
-812
-820
Power leaving MV Prim - kVAr
542
542
540
-238
-258
-244
Load levels - kW
1.59
1.59
1.59
1.59
1.59
1.59
0.523
0.523
0.523
0.523
0.523
0.523
Section
1
2
3
4
5
6
Tx
32.8
17.5
17.1
17.7
16.2
16.2
A
16.6
16.5
16.1
9.1
8.7
8.8
B
20.2
20
19.5
13.7
13.2
13.4
C
18.5
18.3
17.9
15.5
15
15.2
D
15.3
15.2
14.8
15
18.3
18.5
E
13.6
13.4
13.1
13.2
20.1
20.3
F
11.8
11.7
11.4
11.6
21.8
22
G
8.6
8.5
8.3
8.4
8.5
25.3
H
Load levels - kVAr
Loading Matrix
Study Number
6.8
6.7
6.6
6.7
6.8
27
I
5
5
4.9
4.9
5
28.8
J
1.8
1.8
1.7
1.7
1.8
31.9
K
3.1
3
3
3
45.9
3.1
-251 -
Table C2.5 (Cont’d)
Voltage Bus
1
2
3
4
260
1.02
1.029
1.054
261
1.018
1.027
262
1.013
1.022
263
1.008
264
1.003
5
6
1.019
0.977
0.97
1.053
1.02
0.978
0.971
1.047
1.024
0.981
0.975
1.017
1.042
1.028
0.985
0.979
1.013
1.038
1.024
0.99
0.984
265
1
1.009
1.035
1.02
0.996
0.99
266
0.996
1.006
1.032
1.017
1.002
0.996
267
0.994
1.004
1.029
1.015
1
1.003
268
0.992
1.002
1.028
1.013
0.998
1.01
269
0.991
1
1.026
1.012
0.996
1.018
270
0.99
1
1.016
1.011
0.996
1.027
272
0.995
1.004
1.03
1.015
1.03
0.994
Table C 2.6 - 2.5MW; 20V Rural Network; Longest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
233
245
241
Generator Size
-
2.5
2.5
2.5
2.5
2.5
Total Losses - kW
43.7
Total Losses - kVAr
41.7
59.5
26.7
161.2
94.6
69.8
28.2
56.1
24.5
57.1
58.2
Sending Voltage - (200)
1.014
1.025
1.025
1.013
0.974
0.97
Endpoint Voltage - (253)
0.978
0.99
0.989
0.998
0.994
1.029
Fault level - HV (110kV) - (100) - Amps
5359
5379
5378
5372
5354
5353
Fault level - MV (20kV) - Sending (200) - Amps
4122
4585
4559
4498
4224
4226
Fault level - MV (20kV) - Ending (253) - Amps
659
672
671
705
783.3
934
1852
-650
-632
-665
-531
-597
Transformer flow - kW
Transformer flow - kVAr
665
-197
-169
-205
-168
-167
1851
1850
1850
-665
-531
-597
Power leaving MV Prim - kVAr
618
618
618
-211
-172
-172
Load levels - kW
1.81
1.81
1.81
1.81
1.81
1.81
0.595
0.595
0.595
0.595
0.595
0.595
Power leaving MV Prim - kW
Load levels - kVAr
-252 -
Loading Matrix
Study Number
Section
1
Tx
2
3
4
5
6
13
4.5
4.3
4.6
3.7
4.1
A
19.1
18.9
18.9
6.9
5.7
6.4
B
23.4
23.1
23.1
10.9
9.4
10.3
C
20.4
20.2
20.2
13.8
12.5
13.4
D
18.5
18.3
18.3
18.2
14.4
15.3
E
15.6
15.4
15.4
15.3
17.4
18.3
F
13.7
13.6
13.5
13.4
19.3
20.2
G
11.8
11.6
11.6
11.5
21.2
22.1
H
8.8
8.7
8.7
8.6
8.6
25.1
I
6.9
6.8
6.8
6.7
6.7
26.9
J
3.8
3.8
3.8
3.8
3.8
29.9
K
1.9
1.9
1.9
1.9
1.9
31.7
L
2.6
2.6
2.6
2.6
45.2
2.6
Voltage Bus
1
2
3
4
5
230
1.014
1.025
1.025
1.013
0.974
0.97
231
1.012
1.023
1.023
1.014
0.974
0.971
232
1.006
1.017
1.017
1.016
0.977
0.974
233
1
1.012
1.011
1.02
0.98
0.977
234
0.995
1.007
1.006
1.015
0.984
0.981
235
0.991
1.002
1.002
1.011
0.989
0.986
236
0.987
0.999
0.998
1.007
0.994
0.992
237
0.984
0.996
0.995
1.004
1
0.998
238
0.982
0.993
0.993
1.002
0.997
1.005
239
0.98
0.991
0.992
1.001
0.996
1.012
240
0.979
0.99
0.991
0.999
0.995
1.02
241
0.978
0.99
0.989
0.998
0.994
1.029
253
0.978
0.99
0.989
0.998
0.994
1.029
237.5
6
1.056
-253 -
Table C2.7 - 5MW; 20kV Rural Network; Shortest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
204
218
208
Generator Size
-
5
5
5
5
5
Total Losses - kW
11.1
24.55
95
187
426.9
403.87
Total Losses - kVAr
24.7
251.43
351
337.1
398.7
432.37
Sending Voltage - (200)
1.012
1.009
1.013
0.975
0.973
0.973
Endpoint Voltage - (208)
0.998
0.995
0.999
1.015
1.042
1.074
Fault level - HV (38kV) - (100) - Amps
2676
2951
2932
2903
2870
2868
Fault level - MV (20kV) - Sending (200) - Amps
1440
2279
2193
2095
1951
1947
Fault level - MV (20kV) - Ending (208) - Amps
Transformer flow - kW
748
895
881
1116
1299
1606
1097
-3889
-3819
-3726
-3487
-3509
383
-1033
-913
-962
-901
-867
1096
1096
1096
-3740
-3499
-3522
Transformer flow - kVAr
Power leaving MV Prim - kW
Power leaving MV Prim - kVAr
363
363
363
-1186
-1095
-1063
Load levels - kW
1.09
1.09
1.09
1.09
1.09
1.09
Load levels - kVAr
0.36
0.36
0.36
0.36
0.36
0.36
Loading Matrix
Study Number
Section
1
2
3
4
5
6
Tx
22.1
76.6
74.9
73.3
68.6
68.9
A
11.4
11.4
11.5
40.1
37.5
37.6
B
13.5
13.6
13.7
54.3
50.9
51.1
C
12.1
12.1
12.1
55.8
52.4
52.6
D
9
9
9
58.9
55.5
55.7
E
7.5
7.5
7.5
7.4
57
57.2
F
6.1
6.1
6
5.9
58.4
58.6
G
2.9
2.9
2.9
2.9
2.8
61.1
H
1.5
1.5
1.5
1.4
1.4
62.9
P (218)
3.1
3.1
3.1
3.1
90.5
3
Voltage Bus
1
2
3
4
5
6
200
1.012
1.009
1.013
0.975
0.973
0.973
201
1.011
1.008
1.012
0.978
0.976
0.976
202
1.007
1.004
1.009
0.991
0.989
0.988
203
1.005
1.002
1.006
1.005
1.002
1.001
204
1.002
0.999
1.004
1.019
1.015
1.015
205
1
0.998
1.002
1.018
1.029
1.029
206
0.999
0.996
1
1.016
1.043
1.043
207
0.998
0.995
0.999
1.015
1.042
1.058
208
0.998
0.995
0.999
1.015
1.042
1.074
-254 -
Table C2.8 - 5MW; 20kV Rural Network; Average Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
263
272
270
Generator Size
-
5
5
5
5
5
Total Losses - kW
32.8
41.25
110.7
120.7
483.5
476.3
Total Losses - kVAr
58.2
197.9
298.6
239.7
343.2
413.3
Sending Voltage - (200)
1.02
1.018
1.021
0.999
0.97
0.97
Endpoint Voltage - (270)
0.99
0.988
0.991
1.012
1.033
1.101
Fault level - HV (110kV) - (100) - Amps
2896
3171
3153
3139
3073
3061
Fault level - MV (20kV) - Sending (200) - Amps
1483
2328
2241
2190
1919
1885
Fault level - MV (20kV) - Ending (270) - Amps
Transformer flow - kW
607
692
684
794
947
1473
1620
-3371
-3302
-3292
-2929
-2935
583
-917
-817
-875
-772
-747
1618
1618
1618
-3302
-2937
-2943
Transformer flow - kVAr
Power leaving MV Prim - kW
Power leaving MV Prim - kVAr
542
542
542
-1054
-921
-851
Load levels - kW
1.59
1.59
1.59
1.59
1.59
1.59
0.523
0.523
0.523
0.523
0.523
0.523
2
3
4
5
6
Load levels - kVAr
Loading Matrix
Study Number
Section
1
Tx
32.8
66.5
64.8
64.9
57.7
57.7
A
16.6
16.7
16.6
34.5
31.6
31.4
B
20.2
20.3
20.2
47.3
43.4
43.3
C
18.5
18.5
18.5
49
45.2
45
D
15.3
15.3
15.3
15
48.5
48.3
E
13.6
13.6
13.6
13.3
50.2
50
F
11.8
11.8
11.8
11.5
51.9
52
G
8.6
8.6
8.6
8.4
8.2
54.8
H
6.8
6.8
6.8
6.7
6.5
56.6
I
5
5
5
4.9
4.8
58.1
J
1.8
1.8
1.8
1.7
1.7
61.1
K
3.1
3.1
3.1
3
89.2
2.9
-255 -
Table C2.8 (cont’d)
Voltage Bus
1
2
3
4
5
6
260
1.02
1.018
1.021
0.999
0.97
0.97
261
1.018
1.016
1.019
1.002
0.973
0.973
262
1.013
1.011
1.014
1.015
0.985
0.985
263
1.008
1.005
1.009
1.028
0.998
0.997
264
1.003
1.001
1.004
1.024
1.011
1.01
265
1
0.998
1.001
1.021
1.025
1.024
266
0.996
0.994
0.997
1.018
1.039
1.038
267
0.994
0.992
0.995
1.015
1.037
1.053
268
0.992
0.99
0.993
1.013
1.035
1.068
269
0.991
0.989
0.992
1.012
1.033
1.084
270
0.99
0.988
0.991
1.012
1.033
1.101
Table C2.9 - 5MW; 20kV Rural Network; Longest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
233
245
241
Generator Size
-
5
5
5
5
5
119.3
114.8
694.5
490.1
Total Losses - kW
43.7
Total Losses - kVAr
43.7
69.8
69.8
269.7
198.2
348.1
380.7
Sending Voltage - (200)
1.014
1.014
1.009
0.982
0.957
0.972
Endpoint Voltage - (253)
0.978
0.978
0.976
0.988
1.026
1.112
Fault level - HV (110kV) - (100) - Amps
5359
5383
5381
5369
5349
5357
Fault level - MV (20kV) - Sending (200) - Amps
4122
4932
4840
4691
4232
4349
Fault level - MV (20kV) - Ending (253) - Amps
659
678
665
726
884
1408
1852
-3145
-3107
-3077
-2498
-2702
Transformer flow - kW
Transformer flow - kVAr
Power leaving MV Prim - kW
Power leaving MV Prim - kVAr
Load levels - kW
Load levels - kVAr
-256 -
665
-886
-778
-847
-699
-664
1851
1851
1834
-3081
-2500
-2704
618
618
622
-984
-972
-770
1.81
1.81
1.81
1.81
1.81
1.81
0.595
0.595
0.595
0.595
0.595
0.595
Loading Matrix
Study Number
Section
1
Tx
2
3
4
5
6
13
21.6
21.1
21.1
17.1
18.4
A
19.1
19.2
19.1
32.8
27.3
28.8
B
23.4
23.5
23.5
45.1
37.9
39.8
C
20.4
20.5
20.5
48
40.9
42.8
D
18.5
18.6
18.7
18.3
42.8
44.7
E
15.6
15.7
15.7
15.4
45.8
47.6
F
13.7
13.7
13.8
13.5
47.7
49.5
G
11.8
11.8
11.9
11.7
49.5
51.3
H
8.8
8.8
8.8
8.7
8.4
54.1
I
6.9
6.9
6.9
6.8
6.5
55.9
J
3.8
3.8
3.9
3.8
3.7
58.6
K
1.9
1.9
1.9
1.9
1.8
60.3
L
2.6
2.6
2.6
2.6
86
2.5
-257 -
Table C2.9 (cont’d)
Voltage Bus
1
2
3
4
5
6
230
1.014
1.009
1.009
0.982
0.957
0.972
231
1.012
1.007
1.007
0.985
0.96
0.975
232
1.006
1.001
1.001
0.997
0.97
0.986
233
1
0.995
0.995
1.01
0.981
0.998
234
0.995
0.99
0.99
1.005
0.993
1.01
235
0.991
0.986
0.986
1.001
1.005
1.023
236
0.987
0.982
0.982
0.998
1.018
1.036
237
0.984
0.979
0.979
0.994
1.032
1.05
238
0.982
0.974
0.974
0.992
1.03
1.065
239
0.98
0.973
0.973
0.99
1.028
1.08
240
0.979
0.973
0.973
0.989
1.027
1.096
241
0.978
0.973
0.973
0.989
1.026
1.112
253
0.978
0.976
0.976
0.988
1.026
1.112
-258 -
C.3
Power system studies of representative 110/38/10 kV semi-urban network
Tables C.3.1 to C.3.3 present a summary of the significant results of power system studies of the 110/38/10 kV semiurban network, including power flows, power losses, voltage profiles, circuit utilisation and fault levels, for the 1 MW
embedded generation case.
Tables C.3.4 to C.3.6 present the corresponding results for the 2.5 MW embedded generation case and Tables C.3.7 to
C.3.9 the results for the 5 MW generation case.
Table C3.1 - 1MW; 10kV Semi-Urban Network; Shortest Feeder Studies
Study Number
1
2
3
4
5
6
-
200
299
202
203
204
Generator Position
Generator Size
-
1
1
1
1
1
Total Losses - kW
38.15
34.3
39.7
32.2
32
32.4
Total Losses - kVAr
251.7
162
167
161.2
161
161.2
Sending Voltage - (200)
1.012
1.016
1.016
1.016
1.016
1.016
Endpoint Voltage - (204)
1.013
1.013
1.013
1.015
1.016
1.017
Fault level - HV (38kV) - (100) - Amps
5724
5803
5802
5803
5802.8
5802
Fault level - MV (10kV) - Sending (200) - Amps
4961
5308
5305
5306
5305
5304
Fault level - MV (10kV) - Ending (204) - Amps
2601
4406
4400
4460
4486
4510
Transformer flow - kW
4873
3869
3865
3868
3867
3867
Transformer flow - kVAr
1842
1424
1422
1423
1423
1423
Power leaving MV Prim - kW
1195
1194
1194
192
192
193
Power leaving MV Prim - kVAr
393
393
393
64.4
64.3
64.2
Load levels - kW
1.19
1.19
1.19
1.19
1.19
1.19
Load levels - kVAr
0.39
0.39
0.39
0.39
0.39
0.39
1
2
3
4
5
6
Tx
50
39.3
39.3
39.2
39.2
39.2
A
24.8
24.7
24.7
4
4
4
B
18.6
18.5
18.5
2.2
2.2
2.2
C
12.4
12.3
12.3
12.3
-8.3
-8.3
D
6.2
6.2
6.2
6.2
6.2
-14.5
Loading Matrix
Study Number
Section
Voltage Bus
1
2
3
4
5
6
200
1.012
1.016
1.016
1.016
1.016
1.016
201
1.011
1.014
1.014
1.015
1.015
1.015
202
1.01
1.014
1.014
1.016
1.016
1.016
203
1.009
1.013
1.013
1.015
1.016
1.016
204
1.009
1.013
1.013
1.015
1.016
1.017
-259 -
Table C3.2 - 1MW; 10kV Semi-Urban Network; Average Feeder Studies
Study Number
1
2
3
4
5
6
-
200
299
232
238
237
Generator Position
Generator Size
-
1
1
1
1
1
Total Losses - kW
38.15
34.3
39.7
29.95
27.25
27.87
Total Losses - kVAr
251.7
162
167
159.95
158.6
158.8
Sending Voltage - (200)
1.012
1.016
1.016
1.016
1.016
1.016
Endpoint Voltage - (280)
1.005
1.009
1.009
1.011
1.013
1.016
Fault level - HV (38kV) - (100) - Amps
5724
5803
5802
5802
5801
5801
Fault level - MV (10kV) - Sending (200) - Amps
4961
5308
5301
5305
5300
5300
Fault level - MV (10kV) - Ending (237) - Amps
3596
3770
3763
3819
3864
3933
Transformer flow - kW
4873
3869
3869
3865
3863
3862
Transformer flow - kVAr
1842
1424
1424
1422
1420
1421
Power leaving MV Prim - kW
1689
1689
1689
685
682
682
Power leaving MV Prim - kVAr
557
557
557
227
226
226
Load levels - kW
1.68
1.68
1.68
1.68
1.68
1.68
Load levels - kVAr
0.55
0.55
0.55
0.55
0.55
0.55
Loading Matrix
Study Number
Section
1
2
3
4
5
6
Tx
50
39.3
39.3
40
39.2
39.2
A
35
34.9
34.9
14.1
14.1
14.1
B
31.4
31.2
31.2
10.5
10.5
10.5
C
27.7
27.6
27.6
27.5
6.8
6.8
D
24
23.9
23.9
23.9
3.2
3.2
E
11
11
11
11
10.9
9.7
F
7.3
7.3
7.3
7.3
7.3
-13.4
G
3.7
3.7
3.7
3.7
3.6
-17
H
9.3
9.3
9.3
9.3
-11.4
9.3
1
2
3
4
5
6
230
1.012
1.016
1.016
1.016
1.016
1.016
231
1.01
1.014
1.014
1.015
1.015
1.015
232
1.009
1.012
1.012
1.014
1.014
1.014
233
1.007
1.011
1.011
1.013
1.014
1.014
234
1.006
1.01
1.01
1.012
1.014
1.014
234.5
1.005
235
1.005
1.009
1.009
1.011
1.013
1.014
236
1.005
1.009
1.009
1.011
1.013
1.015
237
1.005
1.009
1.009
1.011
1.013
1.016
Voltage Bus
-260 -
1.015
Table C3.3 - 1MW; 10kV Semi-Urban Network; Longest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
264
273
271
Generator Size
-
1
1
1
1
1
38.15
34.3
39.7
24.36
21.75
21.96
Total Losses - kW
Total Losses - kVAr
251.7
162
167
157
155.7
156.1
Sending Voltage - (200)
1.012
1.016
1.016
1.016
1.016
1.016
Endpoint Voltage - (271)
0.973
1.004
1.004
1.008
1.012
1.015
Fault level - HV (110kV) - (100) - Amps
5724
5803
5802
5802
5800
5800
Fault level - MV (10kV) - Sending (200) - Amps
4961
5308
5305
5301
5294
5293
Fault level - MV (10kV) - Ending (271) - Amps
1162
3153
3150
3228
3301
3357
Transformer flow - kW
4873
3869
3865
3859
3857
3857
Transformer flow - kVAr
1842
1424
1422
1420
1418
1418
Power leaving MV Prim - kW
2045
1980
1979
970
967
967
Power leaving MV Prim - kVAr
658
652
652
320
319
319
Load levels - kW
1.96
1.96
1.96
1.96
1.96
1.96
Load levels - kVAr
0.64
0.64
0.64
0.64
0.64
0.64
Loading Matrix
Study Number
Section
1
2
3
4
5
6
Tx
50
39.3
39.3
39.2
39.9
39.1
A
41
40.9
40.9
20
20
20
B
38.3
38.2
38.2
17.3
17.3
17.3
C
35.6
35.5
35.5
14.6
14.6
14.6
D
32.8
32.7
32.7
11.9
11.8
11.8
E
24.7
24.6
24.6
24.5
3.7
3.7
F
21.9
21.9
21.9
21.8
1
1
G
19.2
19.1
19.1
19.1
-1.7
-1.7
H
16.4
16.4
16.4
16.3
-4.4
-4.4
I
8.2
8.2
8.2
8.2
-8.1
-12.5
J
5.5
5.5
5.5
5.5
5.4
-15.2
K
2.7
2.7
2.7
2.7
2.7
-18
L
5.5
5.5
5.5
5.4
-15.3
5.4
-261 -
Table C3.3 (cont’d)
Voltage Bus
1
2
3
4
5
6
1.012
1.016
1.016
1.016
1.016
1.016
261
1.01
1.014
1.014
1.015
1.015
1.015
262
1.008
1.012
1.012
1.014
1.014
1.014
263
1.006
1.01
1.01
1.013
1.013
1.013
264
1.003
1.009
1.009
1.013
1.013
1.013
265
1.002
1.007
1.007
1.011
1.012
1.012
266
1.001
1.006
1.006
1.01
1.012
1.012
267
1.001
1.005
1.005
1.009
1.012
1.012
268
1.001
1.005
1.005
1.009
1.013
1.013
260
268.5
1.004
1.015
269
1
1.004
1.004
1.008
1.012
1.013
270
1
1.004
1.004
1.008
1.012
1.014
271
1
1.004
1.004
1.008
1.012
1.015
Table C3.4 - 2.5MW; 10kV Semi-Urban Network; Shortest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
202
203
204
Generator Size
-
2.5
2.5
2.5
2.5
2.5
Total Losses - kW
38.15
30.16
63.1
32.07
35.12
39.5
Total Losses - kVAr
251.68
67.74
96.8
68.67
70.13
72.3
Sending Voltage - (200)
1.012
1.021
1.021
1.021
1.021
1.021
Endpoint Voltage - (204)
1.009
1.018
1.018
1.023
1.026
1.028
Fault level - HV (38kV) - (100) - Amps
5724
5908
5906
5906
5905
5904
Fault level - MV (10kV) - Sending (200) - Amps
4960
5834
5820
5822
5817
5812
Fault level - MV (10kV) - Ending (204) - Amps
4164
4761
4720
4905
4975
5042
Transformer flow - kW
4873
2365
2362
2367
2370
2375
Transformer flow - kVAr
1842
838
836
839
840
843
Power leaving MV Prim - kW
1195
1194
1195
-1303
-1301
-1296
Power leaving MV Prim - kVAr
393
393
393
-426
-425
-423
Load levels - MW
1.19
1.19
1.19
1.19
1.19
1.19
Load levels - MVAr
0.39
0.39
0.39
0.39
0.39
0.39
Loading Matrix
Study Number
Section
1
2
3
4
5
6
Tx
50
23.9
23.9
23.9
23.9
34
A
24.8
24.5
24.5
26.7
26.7
26.6
B
18.6
18.4
18.4
32.9
32.8
32.7
C
12.4
12.3
12.3
12.2
38.9
38.8
D
6.2
6.1
6.1
6.1
6.1
44.9
-262 -
Voltage Bus
1
2
3
4
5
6
200
1.012
1.021
1.021
1.021
1.021
1.021
201
1.011
1.02
1.02
1.022
1.022
1.022
202
1.01
1.019
1.019
1.0244
1.0244
1.0244
203
1.009
1.018
1.018
1.023
1.026
1.026
204
1.009
1.018
1.018
1.023
1.026
1.028
Table C3.5 - 2.5MW; 10kV Semi-Urban Network; Average Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
232
238
237
Generator Size
-
2.5
2.5
2.5
2.5
2.5
Total Losses - kW
38.15
30.16
63.1
26.72
35.61
34.9
Total Losses - kVAr
251.68
67.74
96.8
66.07
70.43
72.3
Sending Voltage - (200)
1.012
1.021
1.021
1.021
1.021
1.021
Endpoint Voltage - (280)
1.005
1.014
1.014
1.019
1.024
1.032
Fault level - HV (38kV) - (100) - Amps
5724
5908
5899
5906
5901
5900
Fault level - MV (10kV) - Sending (200) - Amps
4960
5834
5786
5820
5794
5791
Fault level - MV (10kV) - Ending (237) - Amps
3596
4020
3987
4145.9
4263
4457.1
Transformer flow - kW
4873
2365
2396
2362
2370
2375
Transformer flow - kVAr
1842
838
865
836
841
842
Power leaving MV Prim - kW
1689
1688
1689
-814
-806
-802
Power leaving MV Prim - kVAr
557
557
557
-265
-261
-259
Load levels - MW
1.68
1.68
1.68
1.68
1.68
1.68
Load levels - MVAr
0.55
0.55
0.55
0.55
0.55
0.55
Loading Matrix
Study Number
Section
1
2
3
4
5
6
Tx
50
23.9
23.9
24.3
23.9
24
A
35
34.7
34.7
16.7
16.5
16.4
B
31.4
31.1
31.1
-20.3
-20.1
-20
C
27.7
27.4
27.4
-27.3
-23.7
-23.7
D
24
23.8
23.8
23.7
-27.3
-27.3
E
11
10.9
10.9
10.9
10.8
-40
F
7.3
7.3
7.3
7.3
7.2
-43.6
G
3.7
3.6
3.6
3.6
3.6
-47.2
H
11
9.3
9.3
9.2
-41.8
9.2
-263 -
Voltage Bus
1
2
3
4
5
6
230
1.012
1.021
1.021
1.021
1.021
1.021
231
1.01
1.019
1.019
1.022
1.022
1.022
232
1.009
1.018
1.018
1.023
1.023
1.023
233
1.007
1.017
1.017
1.022
1.024
1.024
234
1.006
1.015
1.015
1.02
1.025
1.025
234.5
1.03
235
1.005
1.015
1.015
1.02
1.025
1.027
236
1.005
1.014
1.014
1.019
1.025
1.03
237
1.005
1.014
1.014
1.019
1.024
1.032
Table C3.6 - 2.5MW; 10kV Semi-Urban Network; Longest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
264
273
271
Generator Size
-
2.5
2.5
2.5
2.5
2.5
Total Losses - kW
38.15
30.16
63.1
20.52
37.5
21.97
Total Losses - kVAr
251.68
67.74
96.8
64.33
73.4
155.9
Sending Voltage - (200)
1.012
1.021
1.021
1.009
1.002
1.016
Endpoint Voltage - (271)
1
1.009
1.009
1.007
1.011
1.015
Fault level - HV (110kV) - (100) - Amps
5724
5908
5906
5898.6
5898.6
5800
Fault level - MV (10kV) - Sending (200) - Amps
4960
5834
5820
5763.4
5703
5294
Fault level - MV (10kV) - Ending (271) - Amps
3034
3319
3296
3476.7
3655
3357.8
Transformer flow - kW
4873
2365
2362
2355
2372
3858
Transformer flow - kVAr
1842
838
836
830
839
1418
Power leaving MV Prim - kW
1980
1980
1979
-531
-514
968
Power leaving MV Prim - kVAr
652
652
652
-172
-156
319
Load levels - MW
1.96
1.96
1.96
1.96
1.96
1.96
Load levels - MVAr
0.64
0.64
0.64
0.64
0.64
0.64
-264 -
Loading Matrix
Study Number
Section
1
2
3
4
5
6
Tx
50
23.9
23.9
23.8
24
39.1
A
41
40.7
40.7
11
10.7
20
B
38.3
38
38
13.7
13.5
17.3
C
35.6
35.3
35.3
16.5
16.2
14.6
D
32.9
32.6
32.6
19.2
18.9
11.9
E
24.7
24.5
24.5
24.5
27.1
3.7
F
21.9
21.7
21.7
21.8
29.8
1
G
19.2
19
19
19.1
32.6
1.7
H
16.5
16.3
16.3
16.3
35.3
4.4
I
8.2
8.2
8.2
8.2
8.2
12.5
J
5.5
5.4
5.4
5.5
5.5
15.2
K
2.7
2.7
2.7
2.7
2.7
18
L
5.5
5.4
5.4
5.4
-46.2
5.4
-265 -
Table C3.6 (cont’d)
Voltage Bus
1
2
3
4
5
6
1.012
1.021
1.021
1.009
1.002
1.016
261
1.01
1.019
1.019
1.009
1.003
1.015
262
1.008
1.017
1.017
1.01
1.004
1.014
263
1.006
1.016
1.016
1.011
1.004
1.013
264
1.005
1.014
1.014
1.012
1.005
1.013
265
1.003
1.013
1.013
1.01
1.007
1.012
266
1.002
1.012
1.012
1.009
1.008
1.012
267
1.001
1.011
1.011
1.008
1.01
1.012
268
1.001
1.01
1.01
1.008
1.011
1.013
260
268.5
1.017
269
1
1.01
1.01
1.007
1.011
1.013
270
1
1.009
1.009
1.007
1.011
1.014
271
1
1.009
1.009
1.007
1.011
1.015
Table C3.7 - 5MW; 10kV Semi-Urban Network; Shortest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
202
203
204
Generator Size
-
5
5
5
5
5
Total Losses - kW
38
28
161
59
75
95
Total Losses - kVAr
252
13
123
25
33
42
Sending Voltage - (200)
1.012
1.005
1.005
1.005
1.005
1.005
Endpoint Voltage - (204)
1.009
1.002
1.002
1.012
1.017
1.022
Fault level - HV (38kV) - (100) - Amps
5724
6039
6011
6033
6030
6027
Fault level - MV (10kV) - Sending (200) - Amps
4960
6616
6429
6574
6554
6532
Fault level - MV (10kV) - Ending (204) - Amps
4164
5233
5084
5547
5702
5853
Transformer flow - kW
4873
-134
-9
-109
-91
-71
Transformer flow - kVAr
1842
-37
72
-25
-17
-8
Power leaving MV Prim - kW
1195
1183
1200
-3758
-3759
-3750
Power leaving MV Prim - kVAr
393
391
393
-1230
-1227
-1218
Load levels - MW
1.19
1.19
1.19
1.19
1.19
1.19
Load levels - MVAr
0.39
0.39
0.39
0.39
0.39
0.39
Loading Matrix
Study Number
Section
1
2
3
4
5
6
Tx
51
-1
-1
-1
-1
-1
A
25
25
25
-78
-78
-78
B
19
19
19
-84
-84
-84
C
12
12
13
12
-91
-91
D
6
6
6
6
6
-97
-266 -
Voltage Bus
1
2
3
4
5
6
200
1.012
1.005
1.005
1.005
1.005
1.005
201
1.011
1.004
1.004
1.009
1.009
1.009
202
1.01
1.003
1.003
1.013
1.013
1.013
203
1.009
1.002
1.002
1.012
1.017
1.017
204
1.009
1.002
1.002
1.012
1.017
1.022
Table C3.8 - 5MW; 10kV Semi-Urban Network; Average Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
232
238
237
Generator Size
-
5
5
5
5
5
Total Losses - kW
38
28
161
46
115
130
Total Losses - kVAr
252
13
123
20
51
57
Sending Voltage - (200)
1.012
1.005
1.005
1.005
1.005
1
Endpoint Voltage - (280)
1.005
0.998
0.998
0.998
1.018
1.028
Fault level - HV (38kV) - (100) - Amps
5724
6039
6011
6032
6017
6012
Fault level - MV (10kV) - Sending (200) - Amps
4960
6616
6429
6570
6467
6433
Fault level - MV (10kV) - Ending (237) - Amps
3596
4317
4208
4579
4820
5257
Transformer flow - kW
4873
-134
-9
-118
-50
-14
Transformer flow - kVAr
1842
-37
72
-30
1
7
Power leaving MV Prim - kW
1689
1674
1697
3276
-3234
-3203
Power leaving MV Prim - kVAr
557
555
557
-1071
-1045
-1035
Load levels - MW
1.68
1.68
1.68
1.68
1.68
1.68
Load levels - MVAr
0.55
0.55
0.55
0.55
0.55
0.55
Loading Matrix
Study Number
Section
1
2
3
4
5
6
Tx
51
-1
-1
-1
1
0
A
35
35
35
-68
-67
-67
B
31
31
32
-72
-71
-71
C
28
28
28
27
-75
-74
D
24
24
24
24
-78
-78
E
11
11
11
11
11
-91
F
7
7
7
7
7
-95
G
4
4
4
4
4
-98
H
9
9
9
9
-93
9
-267 -
Voltage Bus
1
2
3
4
5
6
230
1.012
1.005
1.005
1.005
1.005
1
231
1.01
1.003
1.003
1.009
1.008
1.003
232
1.009
1.002
1.002
1.012
1.012
1.007
233
1.007
1.001
1.001
1.011
1.015
1.01
234
1.006
0.999
0.999
1.01
1.019
1.014
234.5
1.03
235
1.005
0.999
0.999
0.999
1.019
1.019
236
1.005
0.998
0.998
0.999
1.018
1.024
237
1.005
0.998
0.998
0.998
1.018
1.028
Table C3.9 - 5MW; 10kV Semi-Urban Network; Longest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
264
273
271
Generator Size
-
5
5
5
5
5
Total Losses - kW
38
28
161
56
161
178
Total Losses - kVAr
252
13
123
24.5
71
78
Sending Voltage - (200)
1.012
1.005
1.005
1.005
0.988
0.982
Endpoint Voltage - (271)
1
0.993
0.993
1.013
1.016
1.025
Fault level - HV (110kV) - (100) - Amps
5724
6039
6011
6025
5991
5986
Fault level - MV (10kV) - Sending (200) - Amps
4960
6616
6429
6521
6294
6260
Fault level - MV (10kV) - Ending (271) - Amps
3034
3492
3417
3883
4249
4615
Transformer flow - kW
4873
-134
-9
-100
0.2
0.6
Transformer flow - kVAr
1842
-37
72
-26
23
27.3
Power leaving MV Prim - kW
1980
1962
1989
-2999
-2862
-2887
Power leaving MV Prim - kVAr
652
649
653
-972
-923
-919
Load levels - MW
1.96
1.96
1.96
1.96
1.96
1.96
Load levels - MVAr
0.64
0.64
0.64
0.64
0.64
0.64
-268 -
Loading Matrix
Study Number
Section
1
2
3
4
5
6
Tx
51
-1
-1
-1
0
0
A
41
41
42
-63
-60
-62
B
38
38
39
-65
-63
-64
C
36
36
36
-68
-66
-67
D
33
33
33
-70
-69
-70
E
25
25
25
24
-77
-76
F
22
22
22
22
-80
-81
G
20
20
19
19
-83
-84
H
16
16
17
16
-85
-87
I
8
8
8
8
8
-95
J
6
6
6
5
5
-98
K
3
3
3
3
3
-101
L
6
6
6
5
-96
6
-269 -
Table C3.9 (cont’d)
Voltage Bus
260
1
2
3
4
5
6
1.012
1.005
1.005
1.005
0.988
0.982
261
1.01
1.003
1.003
1.008
0.991
0.985
262
1.008
1.001
1.001
1.011
0.994
0.988
263
1.006
1
0.999
1.015
0.997
0.992
264
1.005
0.998
0.998
1.018
1.001
0.995
265
1.003
0.997
0.997
1.017
1.004
0.999
266
1.002
0.996
0.996
1.016
1.008
1.003
267
1.001
0.995
0.995
1.015
1.012
1.007
268
1.001
0.994
0.994
1.014
1.016
1.011
268.5
1.028
269
1
0.994
0.993
1.014
1.016
1.016
270
1
0.993
0.993
1.013
1.016
1.02
271
1
0.993
0.993
1.013
1.016
1.025
C.4
Power system studies of representative 110/38/10 kV dense urban network
Tables C.4.1 to C.4.3 present a summary of the significant results of power system studies of the 110/38/10 kV dense
urban network, including power flows, power losses, voltage profiles, circuit utilisation and fault levels, for the 1 MW
embedded generation case.
Tables C.4.4 to C.4.6 present the corresponding results for the 2.5 MW embedded generation case and Tables C.4.7 to
C.4.9 the results for the 5 MW generation case.
Table C4.1 - 1MW; 10kV Dense Urban Network; Shortest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
201
202
203
Generator Size
-
1
1
1
1
1
Total Losses - kW
41.92
37.31
42.7
36.2
35.8
36
Total Losses - kVAr
348.72
240.83
245.9
240.2
240
240.1
Sending Voltage - (200)
1.016
1.02
1.02
1.02
1.02
1.02
Endpoint Voltage - (204)
1.014
1.018
1.018
1.019
1.02
1.021
Fault level - HV (38kV) - (100) - Amps
8188
8235
8234
8235 8234
8234
Fault level - MV (10kV) - Sending (200) - Amps
7248
7606.5
7599
7605 7604
7603
Fault level - MV (10kV) - Ending (203) - Amps
6039
6287
6280
6325 6361
6395.2
Transformer flow - kW
5893
4798
4804
4797 4797
4797
Transformer flow - kVAr
2242
1806
1811
1805 1805
1805
Power leaving MV Prim - kW
1112
1112
1112
111
110
111
Power leaving MV Prim - kVAr
367
367
367
38.4
38.1
38.4
Load levels - MW
1.11
1.11
1.11
1.11
1.11
1.11
Load levels - MVAr
0.36
0.36
0.36
0.36
0.36
0.36
-270 -
Loading Matrix
Study Number
Section
1
Tx
2
3
4
5
6
48.8
48.8
48.8
59.2
48.8
48.8
A
23
22.9
22.9
2.3
2.3
2.3
B
15.3
15.2
15.2
15.2
5.3
5.3
C
7.7
7.6
7.6
7.6
7.6
12.9
Voltage Bus
1
2
3
4
5
6
200
1.016
1.02
1.02
1.02
1.02
1.02
201
1.015
1.019
1.019
1.02
1.02
1.02
202
1.014
1.018
1.018
1.019
1.02
1.02
203
1.014
1.018
1.018
1.019
1.02
1.021
Table C4.2 - 1MW; 10kV Dense Urban Network; Average Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
232
234
235
Generator Size
-
1
1
1
1
1
Total Losses - kW
41.92
37.31
42.7
35.25
34.8
35.2
348.72
240.83
245.9
239.7
239.5
239.6
Total Losses - kVAr
Sending Voltage - (200)
Endpoint Voltage - (235)
Fault level - HV (38kV) - (100) - Amps
8188
8235
8234
8235
8235
8235
Fault level - MV (10kV) - Sending (200) - Amps
7248
7606.5
7599
7604
7602
7602
Fault level - MV (10kV) - Ending (235) - Amps
5572
5780
5774
5840
5896
5922.4
Transformer flow - kW
5893
4798
4804
4796
4796
4796
Transformer flow - kVAr
2242
1806
1811
1804
1804
1804
Power leaving MV Prim - kW
1293
1293
1293
291
291
291
Power leaving MV Prim - kVAr
426
426
426
97.3
97.1
97.3
Load levels - MW
1.29
1.29
1.29
1.29
1.29
1.29
Load levels - MVAr
0.42
0.42
0.42
0.42
0.42
0.42
Loading Matrix
Study Number
Section
3
4
5
Tx
1
59.2
2
48.8
48.8
48.8
48.8
6
48.8
A
26.7
26.6
26.6
6
6
6
B
21.4
21.3
21.3
0.7
0.7
0.7
C
16
16
16
15.9
4.6
4.6
D
10.7
10.6
10.6
10.6
9.9
9.9
E
5.3
5.3
5.3
5.3
5.3
15.2
-271 -
Voltage Bus
1
2
3
4
5
6
230
1.016
1.02
1.02
1.02
1.02
1.02
231
1.015
1.019
1.019
1.02
1.02
1.02
232
1.014
1.018
1.018
1.02
1.02
1.02
233
1.014
1.017
1.017
1.019
1.02
1.02
234
1.013
1.017
1.017
1.019
1.02
1.02
234.5
1.013
1.017
1.017
1.019
1.02
1.02
235
1.013
1.017
1.017
1.018
1.02
1.021
Table C4.3 - 1MW; 10kV Dense Urban Network; Longest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
262
266
267
Generator Size
-
1
1
1
1
1
Total Losses - kW
41.92
37.31
42.7
29.45
23.5
26.62
348.72
240.83
245.9
242.04
238.7
240.5
Total Losses - kVAr
Sending Voltage - (200)
1.016
1.02
1.02
1.007
1.007
1.007
Endpoint Voltage - (271)
1.006
1.01
1.01
0.999
1.002
1
Fault level - HV (110kV) - (100) - Amps
8188
8235
8234
8224
8223
8223
Fault level - MV (10kV) - Sending (200) - Amps
7248
7606.5
7599
7531
7526
7529
Fault level - MV (10kV) - Ending (266) - Amps
5192
5370
5364
5369.5
5477
5397
Transformer flow - kW
5893
4798
4804
4789
4783
4787
Transformer flow - kVAr
2242
1806
1811
1803
1799
1802
Power leaving MV Prim - kW
3385
3385
3385
2376
2370
2373
Power leaving MV Prim - kVAr
1113
1113
1113
781
778
780
3.36
3.36
3.36
3.36
3.36
3.36
1.1
1.1
1.1
1.1
1.1
1.1
Load levels - MW
Load levels - MVAr
Loading Matrix
Study Number
Section
1
2
3
4
5
6
Tx
59.2
48.8
48.8
48.7
48.7
48.7
A
69.9
69.6
69.6
49.5
49.3
49.4
B
58.8
58.6
58.6
38.3
38.2
38.3
C
47.7
47.5
47.5
48.1
27
27.1
D
33.4
33.2
33.2
33.6
12.6
33.6
E
22.3
22.2
22.2
22.4
1.4
22.4
F
11.1
11.2
11.2
11.2
9.7
11.2
G
3.3
3.3
3.3
3.3
3.3
-17.6
-272 -
Voltage Bus
3
4
260
1.016
1
2
1.02
1.02
1.007
1.007
5
1.007
6
261
1.013
1.018
1.017
1.005
1.005
1.005
262
1.011
1.015
1.015
1.003
1.003
1.003
263
1.009
1.013
1.013
1.001
1.002
1.002
264
1.007
1.011
1.011
1
1.002
1.001
265
1.006
1.01
1.01
0.999
1.002
1
266
1.006
1.01
1.01
0.999
1.002
1
267
1.009
1.012
1.012
1.01
1.002
1.003
Table C4.4 - 2.5MW; 10kV Dense Urban Network; Shortest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
201
202
203
Generator Size
-
2.5
2.5
2.5
2.5
2.5
Total Losses - kW
41.9
32.45
56.6
33.1
35.3
39.2
348.72
120.5
150.5
120.8
121.9
124
Sending Voltage - (200)
1.016
1.019
1.019
1.019
1.019
1.019
Endpoint Voltage - (203)
1.014
1.017
1.017
1.019
1.022
1.024
Fault level - HV (38kV) - (100) - Amps
8188
8221
8288
8221
8221
8221
Fault level - MV (10kV) - Sending (200) - Amps
7248
7552
8060
7551
7550
3549
Fault level - MV (10kV) - Ending (203) - Amps
6039
6249
6576
6290
6329
6367
Total Losses - kVAr
Transformer flow - kW
5803
3294
3327
3295
3296
3301
Transformer flow - kVAr
2242
1194
1223
1194
1196
1197
Power leaving MV Prim - kW
1112
1112
1112
-1388
-1386
-1381
Power leaving MV Prim - kVAr
367
367
367
-453
-452
-450
Load levels - MW
1.11
1.11
1.11
1.11
1.11
1.11
Load levels - MVAr
0.36
0.36
0.36
0.36
0.36
0.36
2
3
4
5
6
59.2
33.4
33.8
33.4
33.4
33.4
A
23
22.9
22.9
28.5
28.5
28.4
B
15.3
15.3
15.3
15.2
36.1
36
C
7.7
7.6
7.6
7.6
7.6
43.6
Loading Matrix
Study Number
Section
1
Tx
-273 -
Voltage Bus
4
5
6
200
1
1.016
1.019
2
1.019
3
1.019
1.019
1.019
201
1.015
1.018
1.018
1.02
1.02
1.02
202
1.014
1.017
1.017
1.02
1.022
1.022
203
1.014
1.017
1.017
1.019
1.022
1.024
Table C4.5 - 2,5MW; 10kV Dense Urban Network; Average Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
232
234
235
Generator Size
-
2.5
2.5
2.5
2.5
2.5
Total Losses - kW
41.9
32.45
56.6
33.11
37.7
41.1
348.72
120.5
150.5
120.8
123.1
125.1
Sending Voltage - (200)
1.016
1.019
1.018
1.019
1.019
1.019
Endpoint Voltage - (235)
1.013
1.016
1.016
1.02
1.024
1.026
Fault level - HV (38kV) - (100) - Amps
8188
8221
8288
8221
8221
8221
Fault level - MV (10kV) - Sending (200) - Amps
7248
7552
8060
7550
7548
7548
5572.5
5748
6015
5812
5873
5902
Total Losses - kVAr
Fault level - MV (10kV) - Ending (235) - Amps
Transformer flow - kW
5803
3294
3327
3294
3298
3303
Transformer flow - kVAr
2242
1194
1223
1194
1196
1198
Power leaving MV Prim - kW
1293
1293
1293
-1207
-1202
-1198
426
426
426
-394
-391
-390
Power leaving MV Prim - kVAr
Load levels - MW
1.29
1.29
1.29
1.29
1.29
1.29
Load levels - MVAr
0.42
0.42
0.42
0.42
0.42
0.42
2
3
4
5
6
Loading Matrix
Study Number
Section
1
Tx
59.2
33.4
33.8
34.3
33.4
33.5
A
26.7
22.6
26.6
24.8
24.7
24.6
B
21.4
21.3
21.3
30.1
30
29.9
C
16
16
16
15.9
35.3
35.2
D
10.7
10.7
10.7
10.6
40.6
40.5
E
5.3
5.3
5.3
5.3
5.3
45.8
-274 -
Voltage Bus
4
5
6
230
1
1.016
1.019
2
1.018
3
1.019
1.019
1.019
231
1.015
1.018
1.017
1.02
1.02
1.02
232
1.014
1.017
1.016
1.021
1.021
1.021
233
1.014
1.017
1.016
1.021
1.023
1.023
234
1.013
1.016
1.016
1.02
1.024
1.024
235
1.013
1.016
1.016
1.02
1.024
1.026
299
1.013
1.016
1.034
Table C4.6 - 2.5MW; 10kV Dense Urban Networks; Longest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
262
266
267
Generator Size
-
2.5
2.5
2.5
2.5
2.5
Total Losses - kW
41.9
Total Losses - kVAr
32.45
56.6
17.4
15.24
14.8
348.72
120.5
150.5
114.03
112.9
112.6
Sending Voltage - (200)
1.016
1.019
1.019
1.013
1.013
1.013
Endpoint Voltage - (266)
1.009
1.012
1.011
1.001
1.012
1.013
Fault level - HV (110kV) - (100) - Amps
8188
8221
8288
8216
8283
8245
Fault level - MV (10kV) - Sending (200) - Amps
7248
7552
8060
7514
8032
8047
5192.7
5342.7
5563
5377
6000
5785
Transformer flow - kW
5803
3294
3327
3279
3276
3275
Transformer flow - kVAr
2242
1194
1223
1187
1186
1186
Power leaving MV Prim - kW
3385
3384
3385
869
867
867
Power leaving MV Prim - kVAr
1113
1113
1113
286
285
285
3.36
3.36
3.36
3.36
3.36
3.36
1.1
1.1
1.1
1.1
1.1
1.1
Fault level - MV (10kV) - Ending (266) - Amps
Load levels - MW
Load levels - MVAr
Loading Matrix
Study Number
Section
5
6
Tx
1
59.2
33.4
33.8
33.2
33.2
33.2
A
69.9
69.6
69.7
18
18
17.9
B
58.8
58.6
58.6
6.9
6.9
6.9
C
47.7
47.6
47.6
47.7
4.2
4.2
D
33.4
33.3
33.3
33.3
18.5
33.3
E
22.3
22.2
22.2
22.2
29.5
22.2
F
11.1
11.1
11.1
11.1
40.6
11.1
G
3.3
3.3
3.3
3.3
3.3
48.5
-275 -
2
3
4
Voltage Bus
1
2
260
1.016
1.019
1.019
3
1.013
4
1.013
5
1.013
6
261
1.013
1.016
1.016
1.012
1.012
1.012
262
1.011
1.014
1.013
1.012
1.012
1.012
263
1.009
1.012
1.011
1.01
1.012
1.011
264
1.007
1.01
1.01
1.008
1.013
1.01
265
1.006
1.009
1.009
1.007
1.014
1.009
266
1.006
1.009
1.009
1.007
1.016
1.012
267
1.009
1.012
1.011
1.01
1.012
1.013
Table C 4.7 - 5MW; 10kV Dense Urban Network; Shortest Feeder Studies
Study Number
1
2
3
Generator Position
-
200
299
Generator Size
-
5
5
Total Losses - kW
4
5
6
201 202
5
5
203
5
49.1
28.5
158
41
56.5
75
Total Losses - kVAr
349.7
18.9
129.3
24.74
32
40.7
Sending Voltage - (200)
1.016
1.015
1.014
1.015
1.015
1.015
Endpoint Voltage - (203)
1.014
1.013
1.012
1.018
1.023
1.027
Fault level - HV (38kV) - (100) - Amps
8188
8372
8353
8370
8368
8366
Fault level - MV (10kV) - Sending (200) - Amps
7248
8930
8733
8909
8889
8869
Fault level - MV (10kV) - Ending (203) - Amps
6040
7134
6975
7343
7548
7745.4
Transformer flow - kW
5803
790
919
802
817
836
Transformer flow - kVAr
2242
269
379
275
282
290
Power leaving MV Prim - kW
1112
1112
1112
-3876
-3860
-3842
Power leaving MV Prim - kVAr
367
367
367
-1271
-1264
-1256
Load levels - MW
1.11
1.11
1.11
1.11
1.11
1.11
Load levels - MVAr
0.36
0.36
0.36
0.36
0.36
0.36
Section
1
2
3
4
5
Tx
59.2
7.9
9.5
8.1
8.2
8.4
A
23
23
23
80
79.7
79.3
B
15.3
15.3
15.3
15.2
87.3
86.9
C
7.7
7.7
7.7
7.6
7.6
94.5
Loading Matrix
Study Number
-276 -
6
Voltage Bus
4
5
6
200
1.016
1
1.015
2
1.014
3
1.015
1.015
1.015
201
1.015
1.014
1.013
1.019
1.019
1.019
202
1.014
1.014
1.013
1.018
1.023
1.023
203
1.014
1.013
1.012
1.018
1.023
1.027
Table C4.8 - 5MW; 10kV Dense Urban Network; Average Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
232
234
235
Generator Size
-
5
5
5
5
5
Total Losses - kW
49.1
28.5
158
48.95
76.6
93
Total Losses - kVAr
349.7
18.9
129.3
28.32
41.1
48.7
Sending Voltage - (200)
1.016
1.015
1.014
1.015
1.015
1.015
Endpoint Voltage - (235)
1.013
1.012
1.011
1.02
1.028
1.032
Fault level - HV (38kV) - (100) - Amps
8188
8372
8353
8368
8365
8363.4
Fault level - MV (10kV) - Sending (200) - Amps
7248
8930
8733
8895
8859
8841.5
Fault level - MV (10kV) - Ending (235) - Amps
5573
6466
6329
6790
7112
7269
Transformer flow - kW
5803
790
919
810
838
854
Transformer flow - kVAr
2242
269
379
278
291
298
Power leaving MV Prim - kW
1293
1293
1293
-3687
-3659
-3643
426
426
426
-1208
-1196
-1188
Power leaving MV Prim - kVAr
Load levels - MW
1.29
1.29
1.29
1.29
1.29
1.29
Load levels - MVAr
0.42
0.42
0.42
0.42
0.42
0.42
Section
1
2
3
4
5
Tx
59.2
7.9
9.5
8.2
8.4
8.6
A
26.7
26.7
26.7
76.1
75.5
75.2
B
21.4
21.4
21.4
81.4
80.8
80.5
C
16
16
16
15.9
86.1
85.8
D
10.7
10.7
10.7
10.6
91.4
91.1
E
5.3
5.3
5.3
5.3
5.3
96.3
Loading Matrix
Study Number
-277 -
6
Voltage Bus
4
5
6
230
1.016
1
1.015
2
1.014
3
1.015
1.015
1.015
231
1.015
1.014
1.013
1.018
1.018
1.018
232
1.014
1.014
1.013
1.022
1.021
1.021
233
1.014
1.013
1.012
1.021
1.025
1.025
234
1.013
1.013
1.011
1.021
1.028
1.028
235
1.013
1.012
1.011
1.02
1.028
1.032
299
1.013
1.013
1.045
1.021
1.028
Table C4.9 - 5MW; 10kV Dense Urban Network; Longest Feeder Studies
Study Number
1
2
3
4
5
6
Generator Position
-
200
299
262
266
267
Generator Size
-
5
5
5
5
5
Total Losses - kW
49.1
28.5
158
18.6
54.2
27.6
Total Losses - kVAr
349.7
18.9
129.3
14.4
30.9
18.5
Sending Voltage - (200)
1.016
1.015
1.014
1.009
1.009
1.009
Endpoint Voltage - (266)
1.009
1.008
1.007
1.011
1.015
1.017
Fault level - HV (110kV) - (100) - Amps
8188
8372
8353
8360
8352
8357
Fault level - MV (10kV) - Sending (200) - Amps
7248
8930
8733
8840.7
8757
8812
Fault level - MV (10kV) - Ending (266) - Amps
5193
5934
5815
6207.8
6835.6
6360
Transformer flow - kW
5803
790
919
779
815
789
Transformer flow - kVAr
2242
269
379
264
281
268
Power leaving MV Prim - kW
3385
3385
3385
-1626
-1590
-1616
Power leaving MV Prim - kVAr
1113
1113
1113
-535
-519
-531
3.36
3.36
3.36
3.36
3.36
3.36
1.1
1.1
1.1
1.1
1.1
1.1
Load levels - MW
Load levels - MVAr
-278 -
Loading Matrix
Study Number
Section
1
Tx
59.2
2
7.9
3
9.5
4
7.8
5
8.2
6
7.9
A
69.9
69.9
70
33.8
33
33.6
B
58.8
58.8
58.9
44.9
44.1
44.6
C
47.7
47.8
47.8
47.6
55.1
55.7
D
33.4
33.4
33.4
33.3
69.4
33.2
E
22.3
22.3
22.3
22.2
80.4
22.1
F
11.1
11.1
11.1
11.1
91.4
11.1
G
3.3
3.3
3.3
3.3
3.3
100
4
5
260
1.016
1.015
1.014
1.009
1.009
1.009
261
1.013
1.013
1.011
1.011
1.011
1.011
262
1.011
1.01
1.009
1.013
1.012
1.013
263
1.009
1.008
1.007
1.011
1.015
1.015
263.5
1.009
1.008
1.007
1.011
1.015
1.017
264
1.007
1.007
1.006
1.009
1.018
1.013
265
1.006
1.006
1.005
1.008
1.021
1.013
266
1.006
1.005
1.004
1.008
1.025
1.012
Voltage Bus
1
-279 -
2
3
6
Appendix d – example calculations
SEI Costs and Benefits of Embedded Generation
Inputs
Embedded Generation Type
CHP (gas)
Displaced System Plant
Base Load
Generator Size
Generator Utilisation
Connection Voltage
2.5 MW
85%
38kV
Base
Real Power Peak
With Gen
18,298
15572
Reactive Power Peak
8,340
8366
kVAr
Real Power Loss Capacity - Peak
2,384
2342
kW
Reactive Power Loss Capacity - Peak
3,178
2276
kVAr
1.0150
1.0145
Exit Point TLAF
kW
Capital Asset Replacement (Load)
Value
Year
€ 3,000,000
7
10
-280 -
Capital Asset Replacement (Voltage)
Value
€ 500,000
Year
2005
2010
Transmission Capex
Value
€ 3,000,000
Year
2010
2012
System Load Factor
65%
Network Load Factor with Generation
64%Revised Load Factor to be calculated from the revised load profile net of generation output
Empirical Constant
85%
Marginal Capacity Cost
€
200
Estimated replacement marginal cost
Discount Factor
8%
Estimated DCF
Projection Period
15
Years
0.01
/kVArh
Reactive Energy Price
€
From the ESB Networks MV Customer DUoS tariffs for 2004
Emissions Data (values in g/kWh)
CO2
NOx
SOx
Energy Price
Eff
fuel
Technology
Base Load
396.00
0.32
0.00
43.00
50%
Gas
Gas Fired CCGT (BNE Pricing)
Mid Merit
900.00
51.48
13.68
56.00
35%
Coal
Coal Plant (allowed ESB PG Pricing)
<30%LF
720.00
1.73
13.54
60.00
30%
Oil
Conventional Oil Plant
Price
CO2
NOx
SOx
Eff
MCG
Fuel
(c/kWh)
Reliability
Wind
0
0
0
n/a
45.00
Wind
Biomass
0
0
0
n/a
60.00
Biomass
1.50
70%
Peat
0
0
0
n/a
55.00
Peat
1.00
85%
Hydro
0
0
0
n/a
50.00
Hydro
0.00
35%
300
0.4
0
65%
40.00
Gas
1.20
85%
CHP (gas)
-281 -
0.00
25%
Value per Tonne
CO2
€ 15.00
Based on EU ETS expectations
NOx
€ 0.00
Not explicitly valued at present
SOx
€ 0.00
Not explicitly valued at present
-282 -
Displaced Energy Benefit
Step
1
Determine Saving in Annual System Generation
Network Energy Supplied
2
104,188,812
kWh pa
Determined from the studies undertaken for LCTAS and provided generation profile
Network Energy Supplied w Gen
85,573,812
kWh pa
Assumes all embedded generator output offsets demand
Displaced System Generation
18,615,000
kWh pa
Determine System Plant Displaced
Avoided Plant Type
Base Load
Avoided Plant Energy Cost
€
43.00
3
Value of Displaced Energy
€
800,445
4
Cost of generated units
Embedded Generation Type
Embedded generation unit price
5
Net Energy Benefit
Present Value
pa
CHP (gas)
€
Embedded Generator Output
Cost of Embedded Generation
/MWh
40.00
18,615,000
€
744,600
€
55,845
€
478,004
/MWh
kWh
Plant Output offsets energy demand not losses
pa
-283 -
Loss Calculation
Step
1
Establish Network Model
Model of representative network (No Generation)
2
Calculate Network Peak Loading
Network Peak Loading
18298
8340
System Capacity Required
3
6
Marginal Capacity Cost
€
Capacity Cost of Losses
€
2,384
kW
Rural 110_38_10kV load growth analysis; Study 1
3,178
kVAr
Rural 110_38_10kV load growth analysis; Study 1
3,973
kVA
200
/kVA
794,560
Estimated - will need to be quantified and possibly approved by CER
i.e. cost of assets provided purely to service system losses
Calculate Loss Load Factor
Network Load Factor
65%
Empirical Constant
85%
Loss Load Factor (Variable)
46%
Loss Load Factor (Fixed)
65%
Combined LLF
49%
Calculate Energy Loss
10,141,845
kWh pa
DWA Energy Price for Losses
Avoided Plant Type
Avoided Plant Energy Price
8
kVA
Calculate Capacity Loss Value
kWh loss
7
20,109
Includes 110kV, 38kV and 10kV fixed and variable line and Tx losses
System Capacity Required
5
Rural 110_38_10kV load growth analysis; Study 1
Rural 110_38_10kV load growth analysis; Study 1
Calculate Peak Loss Capacity
Peak Loss Capacity
4
kW
kVAr
Base Load
€
43
/MWh
Calculate Value of Energy Losses
€
436,099
pa
-284 -
9
Project Value of Losses
Discount Factor
8%
Evaluation Period
15
Base Loss Value
10
€ 4,527,343
years
no inflation of annual energy loss - calculated in real terms; capacity cost not projected
Establish Network Model
Model of representative network (with Generation)
11
12
Calculate Network Peak Loading
Network Peak Loading
15,572
8,366
kVAr
System Capacity Required
17,677
kVA
Calculate Peak Loss Capacity
Includes 110kV, 38kV and 10kV fixed and variable line and Tx losses
Peak Loss Capacity
System Capacity Required
13
14
15
2,342
kW
2,276
kVAr
3,266
kVA
200
/kVA
Calculate Capacity Loss Value
Marginal Capacity Cost
€
Capacity Cost of Losses
€
653,151
Estimated - will need to be quantified and possibly approved by CER
i.e. cost of assets provided purely to service system losses
Calculate Loss Load Factor
Network Load Factor
64%
Empirical Constant
85%
Loss Load Factor (Variable)
44%
Loss Load Factor (Fixed)
64%
Combined LLF
47%
this is likely to alter following connection of the generation plant dependent on its generating profile
Calculate Energy Loss
kWh loss
16
kW
9,779,049
kWh pa
Prorates loss benefit by the availability of the generator
DWA Energy Price for Losses
Avoided Plant Type
Avoided Plant Energy Price
Base Load
€
43
/MWh
-285 -
17
Calculate Value of Energy Losses
18
Project Value of Losses
€
Discount Factor
420,499
pa
8%
Evaluation Period
15years
Loss Value with Generation
19
€ 3,599,253 no inflation of annual energy loss - calculated in real terms; capacity cost not projected
Determine Net Losses Benefit
Base Loss Value
€ 4,527,343
no inflation of annual energy loss - calculated in real terms; capacity cost not projected
Loss Value with Generation
€ 4,252,404
no inflation of annual energy loss - calculated in real terms; capacity cost not projected
Net Losses Benefit
€
274,939
-286 -
Voltage Benefit Calculation
Step
1 Calculate Reactive Energy
Reactive Power Peak
8,340
Network Load Factor
65%
Reactive Energy
47,487,960
kVAr
Rural 110_38_10kV load growth analysis; Study 1
Assumes that the pf remains constant over the year.
kVArh More accurate to use consumption data from Reactive metering at Transmission exit point
2 Reactive Energy Price
Reactive Energy Price
€
0.006
€
294,425
/kVArh Based on 2004 ESB DUoS tariff for MV connected customers
3 Value of kVArh
Value of kVArh
4 Calculate Voltage Profiles
These will be determined within the normal ESB System planning process
Costs associated with investment in and operation of voltage control will be
5 Determine Cost of Voltage Control
recovered through the DUoS tariffs
6 Calculate Voltage Profiles
These will be determined within the calculation of the LCTAS connection offer.
Additional investment to manage any voltage issues will be caught in that calculation
7 Determine Cost of Voltage Control
Therefore this would be double counting if included here.
8 Calculate Revised Future Capital Reinforcement
Determine the extent to which any voltage driven required system reinforcement implementation
can be delayed after following connection of the embedded generation.
For e.g. If network was on the limit / outside its quality standards then it may require
reconductoring or installation of boosted transformer, or increase in the operating voltage
from 10kV to 20kV. - say this was some 500,000Euros
Deferred Capex
€
500,000
for example (new transformers at the 38kV:MV interface)
Initial Spend Year
2005
as per DNO capital plan prior to generation connection
Revised Spend Year
2010
as per DNO capital plan post generation connection
-287 -
9 Determine Deferred Capex Value
Discount Factor
Value of Deferred Capex
8%
€
136,924
10 Calculate Reactive Energy with Generation
Network Peak Loading
8,366 kVAr
Network Load Factor with Gen
64%
Reactive Energy with Gen.
46,903,142 kVArh
11 Calculate Value of Reactive Energy Saved
Reactive Energy Saved
Value of Saved VArh
584,818 kVArh
€
3,626
Deferred Capex
€
136,924
Saved VArh
€
31,036
Voltage Benefit
€
167,960
pa
12 Overall Voltage Benefit
-288 -
CML Benefit
Step
1
2
Determine Existing Network Statistics
System Average Interruption Duration Index (SAIDI)
60 minutes per interruption
System Average Interruption Frequency Index (SAIFI)
5% - result from analysis of network fault statistics / historic performance
Calculate Expected CMLs
Number of Customers
6000
CMLs
3
18000 minutes
Calculate Value of Lost kWh
Value of Lost Load
€
Network Energy Supplied
7.00
104,188,812 kWh pa
Customer Average Consumption
17365 kWh pa
Energy Supplied per customer minute
0.033kWh per customer minute
Energy Lost due to Network Faults
Value of Lost kWh
4
595kWh pa
€
4,163
€ 35,631
Determine Expected System Statistics
System Average Interruption Frequency Index
6
pa
Project value of Lost kWh
Present Value of Lost kWh
5
/kWh
4%
Investigate Islanding Potential
Is Islanding feasible? ('Y' or 'N')
N
-289 -
7
Restoration Scheme A
System Average Interruption Duration Index (A)
8
Design Islanding Scheme
Islanding Scheme Costs
9
48minutes
€ 250,000
Restoration Scheme B
System Average Interruption Duration Index (B)
10
11
36minutes
Calculate Revised CMLs
Customers within Islanding Scheme
1261customers
Customer Minutes Lost (A)
9099minutes
Customer Minutes Lost (B)
0minutes
Calculate Value of Lost kWh
CMLs
9099minutes
Energy Lost Due to Network Faults
Value of Lost kWh
12
301kWh pa
€
2,104
DUoS Charge
€
0.006
Additional Revenue
€
1.91
pa
Total Savings
€
2,061
pa
Value of loss savings and DUoS
€ 17,637
Calculate Additional DUoS Income
Additional Units delivered
13
14
pa
294kWh pa
/kWh
Project Value of Lost
Net CML Benefit
€ 17,637
-290 -
from 2004 approved ESB Network DUoS charging statement
Asset Benefit
Step
1
Determine Asset Peak Loading without Generator
Peak Demand
18,298
kW
Rural 110_38_10kV load growth analysis; Study 1
Peak Reactive Power
8,340
kVArh
Rural 110_38_10kV load growth analysis; Study 1
Required Network Capacity
20,109
kVA
2
Determine Asset Replacement Date
3
System Peak Loss Capacity Requirements
Asset Replacement Year
7
Peak Loss Capacity
System Capacity Required
4
Rural 110_38_10kV load growth analysis; Study 1 Interpolation
2,384 kW
Rural 110_38_10kV load growth analysis; Study 1
3,178 kVAr
Rural 110_38_10kV load growth analysis; Study 1
3,973 kVA
System Peak Demand Capacity Requirements
Peak Demand Capacity
15,914 kW
Peak System Capacity - Demand
16,136 kVA
5,162 kVAr
5
Determine Asset Peak Loading with Generation
Network Peak Loading
15,572
kW
8,366
kVAr
Required Network Capacity
17,677
kVA
6
Revised Asset Replacement Date
7
Calculate Deferred Capital Benefit
to the extent that the capital expenditure cause was demand led.
Asset Replacement Year
10
Assumes only one investment is affected (there could be multiple instances)
Asset Replacement Capacity
Asset Replacement Cost
15,000
kVA
€ 3,000,000
Discount Factor
Estimated
Need to ensure that this is not double counting any voltage asset benefit.
8%
Present Value without Generation
€ 1,750,471
Present Value with Generation
€ 1,389,580
Deferred Capital Benefit
€
360,891
-291 -
8
System Peak Loss Capacity Requirement w DG
Accounted for within the Loss Benefit
Peak Loss Capacity
2,342kW
2,276kVAr
System Capacity Required
9
3,266kVA
System Peak Demand Requirement w DG
Peak Demand Capacity
13,230 kW
Peak System Capacity - Demand
14,564 kVA
6,090 kVAr
10
Embedded Generation Reliability
Embedded Generation Type
CHP (gas)
Generator Reliability
11
85%
Displaced Load
Displaced kW
12
13
2,281 kW
Value of Displace Load
Demand Network Capacity Charge
€
Value of Displaced Load
€
Net Asset Benefit
€
673,957
-292 -
3,048 per month
36,575 pa
DTS - D1 2004
Transmission System Benefits
Step
1
Exit Capacity without Generation
Network Peak Loading
18298
8340
System Capacity Required
2
20,109
Planned Replacement Year
Ancillary Service Costs without DG
4
Transmission Losses without DG
3,000,000
€
Annual Average System Loss
-
1.0150
Energy Supplied
for example
104,188,812
kWh pa
1,562,832
kWh pa
Losses to supply exit node
Energy Price without DG
€
43.00
Cost of Energy Losses
€
67,202
Rural 110_38_10kV load growth analysis; Study 1
pa
TUoS Charges Without Generation
Demand Network Capacity Charge
-
Accounted for within the Asset (Displaced Load) calculation
Demand Network Transfer Charge
€
246,563 pa
DTS - D1 Tariff 2004
Demand System Services Charge
€
249,293 pa
DTS - D1 Tariff 2004
€
495,855 pa
Total TUoS Income
Exit Capacity with Generation
Network Peak Loading
15,738
System Capacity Required
7
Exit Capacity Saving
8
Asset Replacement with DG
9
kVA
2010
€
3
6
Rural 110_38_10kV load growth analysis; Study 1
Rural 110_38_10kV load growth analysis; Study 1
Asset Replacement
Asset Replacement Cost
5
kW
kVAr
kVAr
17,959
kVA
2,150
kVA
Revised Replacement Year
2012
Deferred Capital Expenditure
€
Ancillary Service Costs with DG
kW
8,652
Interpolation
249,724
€
Would be double counted as covered under Displaced Load
-
-293 -
10
Transmission Losses with DG
Loss rate
1.0145
Energy Supplied at Exit node with DG
85,573,812
kWh pa
1,240,820
kWh pa
Losses to supply exit node
Energy Price with DG
€
Cost of Energy Losses
€
53,355 pa
€
13,847 pa
11
Transmission Loss Benefit
12
TUoS Charges With Generation
Demand Network Capacity Charge
13
for example
43.00 /MWh
-
Accounted for within the Asset (Displaced Load) calculation
Demand Network Transfer Charge
€
202,510 pa
DTS - D1 Tariff 2004
Demand System Services Charge
€
204,752 pa
DTS - D1 Tariff 2004
Total TUoS Income
€
407,263 pa
Net TUoS Benefit
€
88,593 pa
Transmission Benefits
Deferred Capital Expenditure
€
Ancillary Service Benefit
249,724
€
-
Transmission Loss Benefit
€
118,519
TUoS Benefit
€
758,306
€
1,126,549
-294 -
Emission Benefit
Step
1
Determine Avoided Plant Type
Avoided Plant Type
Base Load
Avoided Plant per unit emissions
2
CO2
NOx
SOx
396
0.324
0.000
g/kWh
Avoided System Plant Emissions
Network Energy Supplied
104,188,812
kWh pa
Network Energy Supplied w Gen
85,573,812
kWh pa
Displaced System Generation
18,615,000
kWh pa
Includes effect of losses in distribution network
Emissions Avoided
3
CO2
7,371.54
Tonnes pa
NOx
6.03
Tonnes pa
SOx
0.00
Tonnes pa
Embedded Generator Emissions
Generator Type
CHP (gas)
Embedded Gen per unit emissions
CO2
NOx
SOx
300
0.400
0.000
Embedded Generator Emissions
4
CO2
5,585
Tonnes pa
NOx
7
Tonnes pa
SOx
0
Tonnes pa
CO2
1787.04
Tonnes pa
NOx
-1.41
Tonnes pa
SOx
0.00
Tonnes pa
Net Emission Savings
-295 -
g/kWh
5 Value of Emissions Saved
Per annum
PV
CO2
€
26,806
€
NOx
€
-
€
-
SOx
€
-
€
-
Total
€
26,806
€
Target
Contrib
6 Contribution to National Target
229,442
229,442
CO2
NOx
SOx
Social benefit
Step
Calculate Local Jobs Created
Generator Installed Capacity
1
2.50
Jobs per MW
MW
1.0
for example
Calculate Income from Local Jobs
2
Value of Jobs
€
7,500
pa
Local Income from Jobs Created
€
18,750
pa
Fuel Supply
€
-
Land Rental
€
5,000
for example
Total Local Income from Plant
3
4
Total Local Benefits
Resulting Income Losses
only likely to have real value for Peat or Biomass plant
pa
€
23,750
pa
€
-
pa
€
23,750
pa
€
203,288
not including cost of connection asset way leaves, easements
possibly through job losses at displaced system generation plant
Calculate Geographical and Net Benefit
5
-296 -
Fuel Benefit
Step
1
Displaced Fuel at system level
Displaced Electricity
Displaced Plant Type
3
kWh pa
Base Load
Plant Thermal Efficiency
50%
Fuel Type
Gas
Displaced Fuel Energy
2
18,615,000
37,230,000
kWh pa
Embedded Generation Fuel Use
Plant Type
CHP (gas)
Fuel Type
Gas
Plant Thermal Efficiency
65%
includes for heat usage also
Embedded Generation Output
18,615,000
kWh pa
Fuel Energy
28,638,462
kWh pa
Net Fuel Use Benefit
Fuel Energy Benefit
8,591,538/kWh pa
-297 -
APPENDIX E – Stakeholder Questionnaire
System Charges
Connection charges
Q. 1.
Do the present deep reinforcement connection charging arrangements discriminate against
embedded generators compared to grid connected generation?
Q. 2.
What changes could be made to connection charging policy that would promote the development of
embedded generation?
Q. 3.
Does the Guidelines Connection to the Distribution System, Customer Charter and Standard
Connection Agreement aid the process of connecting embedded generation in terms of :
a.
A defined connection offer/delivery timetable?
b.
A defined schedule of charges?
c.
Contestability of connection?
Use of system charges
CHP issues
Q. 4.
What changes could be made to promote EG.
Q. 5.
Do the existing use of system charging arrangements favour any particular type of generation, i.e
favouring ?
Q.6.
Would a change in use of system policy for CHP make this form of generation more financially attractive, or is
gas price the major factor
Q.7.
Is the above considered to be a significant barrier to entry?
Q.8
Have CHP generators been able to obtain competitive contracts with suppliers?
Treatment of losses
Q.9.
What changes could be made to promote EG.
-298 -
Trading arrangements
Compliance with EU Directive 2001/77/EC
Q.10
Is the limit (10 MW units associated with TUoS charges or 30MW for self despatch) perceived as a barrier to
larger wind farms?
Perceived benefits for renewables and embedded generation
Guaranteed market for RE
Q.11
Response requested:
Removes risk of top-up and spill pricing differentials
Q.12
Response requested:
Closer to real time dispatch allowing more accurate trading
Q.13
Response requested:
Locational marginal pricing for generation
Q.14
As, the location of embedded generation is more likely to be resource driven (especially for CHP, wind and
hydro plants) rather than being strongly influence by LMP’s, should embedded generation pay location marginal
prices?
Q.15
Alternatively should embedded generation be seen as negative demand and pay (typo, should be get
paid) the Uniform Wholesale Spot Market price?
Q.16
Should this decision be linked to the capacity limits for dispatchable plant, or related to the individual
operator’s choice of whether its plant is dispatchable or not
Allowable trading strategies
Q.17
Whilst allowing a negative pricing strategy clearly favours conventional generation plant, do the proposed
trading arrangements disadvantage renewable and embedded plant that will be totally exposed to the volatility of a
market price that is set by other, predominantly thermal, generation?
Q.18
Will the inflexibility of thermal generation dominate the market trading arrangements such that it is
effectively making renewable and embedded generation fit in around a thermal based market, instead of setting a
level playing field?
Q.19
Should the new market arrangements provide a greater signal to increase thermal plant flexibility by
setting a zero price level for all?
Q.20
Should the price floor for renewables be zero or a negative value in line with any implied subsidy?
-299 -
Q.21
Does such a strategy contradict the requirements of EU Directive 2001/77/EC as it will force renewable
generation to switch off for financial reasons, and not that of grid security?
Q.22
Do the existing and proposed trading arrangements cause sufficient financial uncertainty to deter
investment in renewable and embedded generation?
Q.23
Should intermittent generators be price takers or should they be allowed to set the market price at certain
times of the day?
Appropriate allocation of market reserve costs
Q.24
Is CER’s position in line with 2001/77/EC directive?
Q.25
Should costs of reserve be allocated across all demand and passed onto demand customers?
Q.26
Should individual generators be liable for their contribution to reserve requirements, e.g. large thermal as
well as intermittent generation?
Use of financial hedging tools such as CfDs.
Q.27
What support mechanisms should be implemented?
Q.28
Would market based systems such as CfDs be sufficient to support the step change in development of RE
and embedded generation required to meet stated Government and EU targets?
Q.29
Will CfDs provide sufficient financial certainty to investors or can this only be determined through market
experience and hence new RE and EG is likely to be postponed in the short to medium term (chicken and egg
situation)?
Micro-generation
Q.30
What method of metering and payment for exports would best encourage micro-generation (in particular
small and domestic CHP), both from a customer and a supplier point of view?
General Questions:
Q.31
Should the operation of Renewable Energy be
i.
outside of the proposed pool mechanism;
ii.
non-dispatchable;
iii.
must run?
ESB’s dominant market position
Q.32
What is the perceived effect of ESB’s market position?
-300 -
Q.33
How can relatively small generators compete on a level playing ground with larger conventional
generation?
Technical issues
Q.34
To what extent does uncertainty with respect to connection requirements, costs and timescale
discourage/complicate embedded generation connections.
Q.35
Do the stakeholders have a view on any of the technical issues discussed above that they may see as a
particular barrier to the future development of embedded generation on the network.
The questionnaire was distributed to the following stakeholders:
•
Saorgus
•
Meitheal na Gaoithe
•
CER
•
ESB Networks
•
ESB National Grid
•
Hibernian Wind Power
•
Irish Wind Energy Association
•
Irish Hydropower Association
•
Irish Combined Heat & Power Association
•
Airtricity
-301 -
Costs and Benefits of Embedded Generation
Micro-Generation Addendum
-i -
CONTENTS
1.
2.
Introduction
Review of Perceived Costs and Benefits of Micro and Small Scale Embedded Generation
(SSEG)
3.
4.
5.
1
2
2.1
Introduction
2
2.2
Utilisation of Network Assets
3
2.3
System Losses
3
2.4
Voltage Regulation
3
2.5
Voltage Unbalance
4
2.6
Power Flow
4
2.7
Fault Levels
4
2.8
Voltage Step Changes
4
2.9
Generation Location
4
Representative Network Identification and Modelling
5
3.1
System Model
5
3.1.1
Introduction
5
3.1.2
Input Data
5
3.1.3
System Loading
7
3.2
Studies and Results
8
Treatment of Costs and Other Issues Related to Connection of Embedded
Micro-Generation
13
4.1.1
Inherent Characteristics of Micro-Generation
13
4.1.2
Connection Process for Micro-Generation
13
4.2
Calculation of Costs and Benefits
14
4.3
Apportioning Costs and Benefits
4.4
Next Steps
References
14
14
16
1. Introduction
This report forms an addendum to the PB Power report for Sustainable Energy Ireland entitled ‘Costs and Benefits of
Embedded Generation – Final Report’. This addendum focuses on micro-generation.
Definitions of micro-generation vary, but this addendum focuses on generating units rated up to 16A per phase,
these are likely to be single phase and connected at 230V within a domestic or light commercial property. Devices
that are close to market are in the 1kW to 5kW range.
This addendum describes the high level costs and benefits that would be seen by ESB Networks with the connection
of micro-generation onto its LV network. This is a qualitative description which keys into the discussion and items
raised in Section 3 "Review of Perceived Costs and Benefits of Embedded Generation" within the main report.
There is also a description of a typical ESB urban LV network and its characteristics, and a brief analysis of the effects
of micro-generation on that network. The impact of the positioning and quantity of micro-generation is examined.
Finally, recommendations have been made on how the connection of such small units may be assisted.
This addendum should be read in conjunction with the main report.
-1-
2. Review of Perceived Costs and Benefits of Micro- And Small Scale
Embedded Generation (SSEG)
2.1
Introduction
In this section we identify the potential costs and benefits that can be obtained from the connection of embedded
micro-generation to the distribution network. A full analysis has been carried out in the main report for all types of
embedded generation. This addendum therefore summarises where there are any differences in emphasis for microgeneration. Micro-generation differs from other types of embedded generation in that: •
each generator is typically in the 1 to 5 kW range, and is located within domestic or light commercial
premises
•
the generators are connected to the low voltage, 230V, single phase network and in most cases there will
only be one possible connection point
•
the load is connected at the same point as the generator, or else where there is a mismatch between
generation output and load required, there will be transfer over a very short distance
•
the reduction in demand and possible export from an individual device is relatively small, but significant
for multiple devices
•
the effect on the distribution network is minimal for a single device, and the only connection cost is that
associated with the local connection of the device
•
for multiple devices there may eventually need to be changes and modifications to the existing
distribution system
The contribution from SSEG units will be effected at the point of use of electricity for LV consumers. This means that
these units will be able to offset the LV system losses to a greater or lesser extent. As identified in Table 3.2 of the
main report, the losses in the MV/LV transformation and LV network amount to some 35% of the overall transmission
/ distribution system losses and almost 50% of the typical distribution system loss. Therefore there is significant
value from SSEG both in terms of its potential to avoid load related capital expenditure and to offset energy loss
costs.
The connection of significant quantities of SSEG to a particular LV distribution network will present itself on the MV
or HV network in a similar way to a direct connected larger embedded generator and the costs and benefits
discussed in Sections 3.1 through 3.9 of the main report will be evident. The discussion below considers some of
these items further in relation to SSEG connections;
-2-
2.2
Utilisation of Network Assets
Micro-generation is, by its nature, connected close to its load. Its overall effect is to reduce demand on the system.
With micro-generation the upstream assets will be the assets from the LV feeder upwards, so the reduction in
utilisation prolongs the life of a greater range of assets.
Consider, for example, an urban distribution network where there is a concentration of households using gas central
heating, and who have installed micro-CHP. Micro-CHP is generally sized to supply the average domestic load, but
will only operate when the central heating system is on. When the majority of households with micro-CHP are using
their central heating systems, there will be a reduction in the system demand. This will reduce the winter demand on
cables and transformers connected upstream of the micro-generators and so prolong the life of the upstream assets.
There will also be a reduction in the winter peak demand. The extent of the reduction in winter peak will be a
function of the number of installations and the diversity to be expected in their use. This could allow network
reinforcement to be delayed or even avoided. At the times of day and year that the micro-CHP sets are not operating
then the system demand will be unchanged.
There will also be times when the micro-CHP installations could be feeding power back up through the LV network,
for example, in the summer when hot water is required but electrical demand is low. Given the small sizes of
individual installations, and the expected diversity in the behaviour of different users, this not a highly likely scenario.
Previous studies carried out on similar LV networks have shown that this scenario would not overload existing assets,
but could potentially cause voltage control problems.
Other types of micro-generation, for example photovoltaic, are also generally sized to supply the average domestic
load, but the output will depend upon the climatic conditions. They will tend to be at full output when the microCHP devices are not (warm, sunny weather), and will have a different effect on the demand profile.
2.3
System Losses
Micro-generation effectively reduces system demand during the winter months, when central heating is being used
(for micro-chp), and at other times depending upon the climatic conditions (PV and wind). Since the generation is
local to the load, the system losses will be reduced during these periods. The peak load power loss will certainly be
reduced, and it is very likely that energy losses will be reduced.
There may be short periods of time when there could be an increase in energy losses, because there is a net export
of power back up through an LV feeder. This is an unlikely, and certainly short duration scenario, since it would only
occur if, for example, all of the householders in a particular area used their micro-CHP for heating or hot water at a
time when they were not using their high demand electrical appliances. This scenario would be outbalanced by the
longer duration, and more likely, scenarios, in which energy losses are reduced or maintained at current levels.
Theses scenarios would be where all of the householders in a particular area, for example, had their central heating
switched on whilst using their high demand electrical appliances, or were using their electrical appliances without
any micro-generation (the current situation).
-3-
2.4
Voltage Regulation
The units will provide voltage support to the LV network through the displacement of demand at the point of use.
The voltage profile for the LV Network and the tap setting on the local MV/LV distribution transformer will determine
the extent to which the voltage rise may exceed accepted distribution network ‘ design’ limits. However, there is the
potential to adjust the MV/LV transformer taps (off-circuit) on that part of the system to take into account the
changed voltage profile.
2.5
Voltage Unbalance
There is a ‘background’ level of voltage imbalance on LV networks due to the random connection of users to
particular phases along a feeder. This effect is more pronounced the further away from the distribution transformer.
The voltage imbalance at the distribution transformer LV terminals is lower since they are not affected by the feeder
cable voltage drops and this will mitigate the impact of multiple SSEG on voltage unbalance at the MV and HV levels.
2.6
Power Flow
Whilst the SSEG penetration remains below the level of demand on an LV network it is unlikely that there will be
issues related to reverse power flow through the distribution transformer. However, should there be reverse flow
(real power or reactive power) through the distribution transformer there may be issues related to the protection
systems and tap changer equipment associated with the transformer, and there could well be cost issues for the
connection of the SSEG beyond this level.
The distribution company may need to consider providing statements on the allowable penetration of SSEG on their
LV networks and certainly should consider a mechanism for treatment of connections that require capital
expenditure on the LV network.
2.7
Fault Levels
The introduction of multiple SSEG units onto an LV network will increase the fault level. However, recent studies for
the UK distribution system, have shown that the impact is not significant due to the impedance of the LV network.
Further, the contribution to the fault level at higher voltage levels has also been shown to be minimal.
2.8
Voltage Step Changes
The SSEG units may be sensitive to the voltage transients that can be seen on LV networks, say from the
disconnection of an adjacent distribution transformer. If this is the case it is likely that the action of circuit breakers
or fuses local to the fault will not cause loss of supply to the un-faulted transformer. However, protection equipment
on the SSEG units may operate and trip the generation and this secondary effect will result in voltage step change.
This may lead to a standard range of protection settings for SSEG plant on a given LV network, or possibly a generic
‘fault ride through’ capability.
-4-
2.9
Generation Location
The location of the SSEG units on the LV network will influence the extent of their effect on the LV network. Those
located at the remote end of feeders will have the greatest impact on the ability of the remote end voltage to stay
within design limits. The location on the MV/HV network of those LV networks with significant SSEG penetration will
have a similar influence on the MV/HV networks as does the location of a larger directly connected embedded
generator.
-5-
3. Representative Network Identification and Modelling
3.1
3.1.1
System Model
Introduction
Studies have previously been carried out for the UK urban distribution system, to examine the effect of increasing
levels of micro-generation. The ESB urban low voltage system is similar in topology, but there are differences in the
voltages used, the transformer sizes and the cable sizes used. A representative ESB urban low voltage system has
therefore been modelled to check whether the conclusions drawn from studying UK distribution systems are also
valid for ESB low voltage systems.
The network used has tapered cables, this is no longer ESB practice, but would be typical of the older ESB low
voltage urban networks in-situ, to which domestic micro-generation would be connected.
3.1.2
Input Data
The generic urban model is shown in figure 3.1. Table 3 summarises the data used.
Each 10kV feeder represents a 3.0km feeder cable supplying ten 10/0.433kV 400kVA ground mounted distribution
transformers and 400V substations. Four of the feeders are modelled as simple lumped loads whilst the fifth feeder
is represented in full detail.
Each 400V substation represents an urban cable distribution system with four outgoing radial feeders, each 300m
long. There are a total of 312 domestic single-phase house loads, distributed equally between the feeder cables. The
feeder cables are tapered and the loads are distributed evenly along the length of the cable. Since the domestic
loads are single phase, each point of connection, or service joint, on the feeder cable supplies three domestic loads,
one connected to each phase. From a modelling perspective, there are therefore 26 three phase loads spaced evenly
along the length of the feeder cables. Three of the 400V feeders are represented as simple lumped loads with only
the fourth being represented in detail.
The micro-generator is nominally 230V, 50 Hz, and 1.1kW single phase, operating at a power factor of 0.95 lagging or
unity.
-6-
Figure 3.1 38/10/0.4 kV Power System Model used in the Simulations
500MVA Source
Total load of 10MVA
assuming 0.5 load factor
at 10/0.433kV
38/10.5kV
transformation level
10MVA
18%
YY0
11kV controlled to
between 11.0kV and
11.1kV
10 off 10/0.433kV
4 off Feeders each of
400kVA
2MVA demand
substations equally
assuming 0.5 load
spaced on 10kV
factor
feeder. Total load
of 2MVA assuming
0.5 load factor
4 feeders on LV
4 off 375m lengths of
switchboard giving total
185mm2 10kV PICAS
ADMD of 400kVA
(total of 1.5km)
216.2V≤ V ≤ 253V
0.164 + j0.08Ω/km
150m of 185mm2
415V CNE
0.164 + j0.074Ω/km
(phase)
0.164 + j0.014Ω/km
(neutral)
4 off 375m lengths of
95mm2 10
kV PICAS (total of
150m of 95mm2 415V
1.5km)
CNE
0.32 + j0.087Ω/km
78 customers
equally spaced
each with an
ADMD of
1.28KVA.
0.32 + j0.075Ω/km
Total feeder
(phase)
ADMD of
0.32 + j0.016Ω/km
100kVA
(neutral)
Service cable
30m of 35mm2 CNE to each customer
0.851 + j0.041Ω/km (phase)
0.90 + j0.041Ω/km (neutral)
-7-
Table 3 Generic Model Data
Component
Description
10kV detailed Feeder
•
Circuit
•
Comments
Fourth feeder circuit comprising 10 x 400kVA substations.
2
Feeder cable comprises 1.5km of 185mm 3 core PICAS
185mm2 Cable
parameters: -
2
plus 1.5km of 95m 3 core PICAS
•
400KVA substations distributed equally along 3km feeder
0.164 + j0.080•/km
95mm2 Cable
parameters: 0.32 + j0.087•/km
10/0.433kV
•
Comprises one 400kVA transformer
Three feeders modeled
Substation
•
Four outgoing 400V 3 phase feeders
as lumped loads and
•
ADMD of each feeder is 100kVA
generators
•
No load volts < or = 253V
•
Full load volts > or = 220 V
•
Load factor = 0.5 (MD on sub is 200kVA)
•
312 customers supplied
•
ADMD = 1.28kVA per customer
10/0.433kV
•
400kVA
Transformer
•
5% impedance
•
Dy11 windings
•
X/R ratio of 15
•
Taps set at 0% on HV side
•
Off load ratio of 10/0.433kV
•
Feeder comprises two segments of cable, 150m of
185mm2 Cable
185mm2 CNE and 150m of 95mm2 CNE cable
parameters: -
•
78 customers distributed evenly along feeder
0.164 + j0.074•/km
•
customers distributed evenly across three phases
(phase)
•
Service joints distributed evenly along feeder cable
0.164 + j0.014•/km
segments
(neutral)
Up to four consumers per service joint
95mm2 Cable
400V Detailed
Feeder
•
parameters: 0.32 + j0.075•/km (phase)
0.32 + j0.016•/km
(neutral)
Individual customers
•
ADMD of 1.28kVA, 1.0pf
Cable parameters: -
•
Minimum demand of 0.16kVA, 1.0pf
0.851 + j0.041•/km
•
Micro-generator of 1.1kVA, 0.95pf
(phase)
•
30m of service cable, 35mm2 CNE
0.9 + j0.041•/km (neutral)
•
G74 motor load fault in-feed
-8-
3.1.3
System Loading
Each 10kV feeder supplies ten 10/0.433kV 400kVA transformers. The feeder is therefore designed to supply the full
load of each transformer, giving a total feeder load of 4MVA. This is unlikely to occur in practice due to the diversity
of demand, therefore a load factor is normally applied to the substation loads to provide a more representative
maximum feeder demand. For a load factor of 0.5 the total feeder load would reduce to 2MVA, or 200kVA per
substation.
With five 10kV feeders the total load on the 10kV substation is 20MVA. This reduces to 10MVA when the 0.5 load
factor is taken into account, giving a load of 100% of the firm capacity of the 38/10.5 kV transformers. This is
pessimistic, since it is the highest load that could be supplied by this substation.
The feeder cables from the 10/0.433kV substation are also designed to supply the estimated maximum demand of
the connected services. Load demand figures produced by the UK Electricity Association data show that the
minimum and maximum demand figures are 0.16kVA and 1.3kVA respectively. Irish domestic demand figures have
been assumed to be similar. With 78 consumers connected to a single feeder cable, the maximum demand at the
substation would be approximately 100kVA. This allows up to four such feeder cables to be fed from each 400kVA
substation. For the 10kV system it is unlikely that the maximum demands on the feeders coincide and a load factor
is normally used to take account of the diversity.
3.2
Studies and Results
Previous studies, for the UK distribution system, identified the threshold levels of micro-generation that could
necessitate distribution system or equipment changes. The studies were pessimistic, in that they considered
extremes of operation, namely: •
Maximum load, zero generation
•
Minimum load, zero generation
•
Maximum load, maximum generation
•
Minimum load, maximum generation
The first two cases represent the current extremes of operation for the network. The third and fourth cases are
unlikely future scenarios, given the likely diversity in micro-generation technologies and users’ behaviour patterns,
but do give the worst cases. These extreme cases have been studied for the ESB representative urban low voltage
network described above.
The studies confirmed the validity of the conclusions drawn in previous studies on similar systems. The key issues
that can require distribution system changes as a result of multiple connection of SSEG are: •
reverse power flows, when the generation exceeds demand for the system, such that there is reverse flow
(real power or reactive power) through the distribution transformer
•
voltage rise at the remote end of the LV feeder due to reverse power flows
-9-
The penetration levels of SSEG at which this occur will depend upon the design of the network, the distribution of
the SSEG down the feeder, and the operational profile of the SSEG, compared with the local demand profile.
Typically a concentration of SSEG in premises connected at the far end of a long 10kV feeder would give the greatest
difficulties with voltage rise.
There are other issues that can arise, including voltage unbalance and increases in fault level, however, these only
become an issue at higher levels of SSEG.
The worst case for voltage rise occurs when there is maximum generation and minimum load. Graph 3.1 illustrates
this for the particular network studied, with maximum generation (1.1kW per consumer) distributed uniformly. The
graph shows the voltage profile down the 10kV feeder to the remotest 10kV/400V supply point, and then along that
remotest 400V feeder to the end. The voltage rise at the remote end is due to the flow of real power back up through
a mainly resistive network. For this particular scenario, it can be seen that the voltage rise at the remote end is at
+10% above nominal. For this particular network, it would therefore be possible to connection a 1.1kW generator
within each consumer’s premises without having voltage problems.
Graphs 3.2 and 3.3 illustrate the voltage along the same feeder for the two extremes of operation without SSEG,
namely maximum load and minimum load. It is important that ESB gain an understanding of the levels of SSEG
penetration, network designs and locations for which widespread connection should not cause any concerns.
- 10 -
Graph 3.1
System Voltage Profile for maximum generation, minimum load
1.15
1.10
1.00
0.95
0.90
Voltage
Limits
System Voltage
Profile
- 11 -
Location
5
Se
g
LV
Se
g
4
3
LV
Se
g
2
LV
Se
g
1
LV
Se
g
LV
10
M
V
Su
b
Su
b
9
8
M
V
Su
b
M
V
Su
b
7
6
M
V
Su
b
5
M
V
Su
b
4
M
V
Su
b
3
M
V
Su
b
2
M
V
Su
b
1
M
V
Su
b
M
V
at
io
M
V
Su
bs
t
Su
pp
l
V
H
n
y
0.85
So
ur
ce
Voltage (pu)
1.05
M
V
V
- 12 -
Location
LV
LV
LV
LV
9
8
7
6
5
4
3
2
1
n
y
Se
g
Se
g
Se
g
Se
g
Se
g
5
4
3
2
1
10
Su
b
Su
b
Su
b
Su
b
Su
b
Su
b
Su
b
Su
b
Su
b
Su
b
LV
M
V
M
V
M
V
M
V
M
V
M
V
M
V
M
V
M
V
M
V
at
io
Su
pp
l
Su
bs
t
H
So
ur
ce
Voltage (pu)
Graph 3.2
System Voltage Profile for zero generation, maximum load
1.15
1.10
1.05
1.00
0.95
0.90
0.85
M
V
V
- 13 -
Location
LV
LV
LV
LV
9
8
7
6
5
4
3
2
1
n
y
Se
g
Se
g
Se
g
Se
g
Se
g
5
4
3
2
1
10
Su
b
Su
b
Su
b
Su
b
Su
b
Su
b
Su
b
Su
b
Su
b
Su
b
LV
M
V
M
V
M
V
M
V
M
V
M
V
M
V
M
V
M
V
M
V
at
io
Su
pp
l
Su
bs
t
H
So
ur
ce
Voltage (pu)
Graph 3.3
System Voltage Profile for zero generation, minimum load
1.15
1.10
1.05
1.00
0.95
0.90
0.85
4.
Treatment of Costs and Other Issues Related to Connection of
Embedded Micro-Generation
4.1.1
Inherent Characteristics of Micro-Generation
As discussed in Section 2.1, there are some very fundamental differences between micro-generation connected to
the LV network and larger embedded generators connected at 10kV and 38kV. There are other characteristics that
affect the treatment of costs and benefits, namely:
•
the owner and operator of the generator is likely to be the domestic or commercial consumer, i.e. the
Generator and Customer are one and the same entity
•
the owner and operator will have limited knowledge of trading arrangements
•
micro-generators are likely to be mass-market devices. For the particular case of micro-CHP, 80% of
installations are likely to occur when the existing central heating boiler fails. Rapid and simple connection
is required for these ‘distressed purchases’
4.1.2
Connection Process for Micro-Generation
Applying the embedded generation connection application process to SSEG generation plant will be a significant
barrier to market entry. It will effectively restrict competition in the supply market and prevent end users from
having a free choice of energy supplier. The connection process for larger embedded generation requires the
parties involved in the transaction to be informed participants with development resource and an understanding of
the mechanisms in place for regulation of the electricity industry. It also requires a timescale that is incompatible
with ‘distressed purchases’.
Given that the expected end user for SSEG will be a typical domestic customer, the position is significantly different.
The product will be sold on the basis of its utility and cost saving potential meaning that, as with consumer goods
and commodities, the transaction process (which will include the electrical connection) will need to be as standard
as possible within the statutory constraints of the distribution licence. Such standardised connection terms could be
applicable for SSEG below a de-minimis level to be determined.
In the UK this approach has been taken for devices with a rating of 16A per phase or less, through the use of
Engineering Recommendation G83/1. G83/1 specifies all of the technical interface requirements that the generation
unit must meet, including isolation, protection, earthing, and EMC emission standards. Type testing of the
generation units is required in order to demonstrate that the units meet the G83/1 requirements.
G83/1 also outlines very clearly the process that needs to be followed with the distribution network operator in
order to connect small generators. It offers the option of a very simple and quick process for single installations, and
a more lengthy but straight forward process for multiple installations, where the distribution network operator will
need to look more closely at network design issues.
A European approach to the connection of micro-generation is being developed. The first step in this was a CEN
Workshop Agreement, and this is currently being developed into a European Norm.
It is essential that ESB develop a simpler and more rapid connection process for micro-generation, based on similar
principles to those used in the UK, and being developed at the European level.
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4.2
Calculation of Costs and Benefits
The benefits that accrue for larger embedded generators with direct connections to the MV and HV distribution
network will also accrue for SSEG connected to LV networks. The cumulative benefit for multiple SSEG’s could
actually be higher than for an equivalent size larger generator, given the additional energy and losses savings.
The same calculation approach as that used for the larger generators could also be used to identify the costs and
benefits associated with SSEG, however it would not be possible or desirable to integrate it into the connection
process. The calculation would also need an understanding of the likely operating regime of the SSEG versus the
demand profile. Rather than evaluating individual SSEG’s, a more efficient approach would be evaluate the costs and
benefits associated with forecast levels of SSEG, taking into account likely penetrations of different SSEG
technologies on different types of ESB networks (urban, rural etc). This would be a significant piece of work requiring
forecasts of SSEG market penetration.
The impact of SSEG connections on distribution networks will develop over time, as market penetration increases.
This will allow ESB Networks to take account of it within their LV network designs in a similar way to their projections
of load growth that drive the load related expenditure. It will also enable a considered approach as to how the costs
and benefits can be calculated and apportioned.
4.3
Apportioning Costs and Benefits
A number of approaches would be possible. Reward mechanisms should be efficient (i.e. in economic terms),
encourage competition, be transparent (i.e. easily understood), be accessible to those qualifying for them, and be
robust in the long term.
Recent work carried out in the UK for the Distributed Generation Co-coordinating Group identifies alternative
approaches in some detail.
One approach would be to develop standardised SSEG connection terms that would provide a sliding scale of
connection charges linked to the generator capacity, and incorporating the costs and benefits associated with
typical import/export profiles for this class of customer. However given the minimal effect that individual SSEG’s
have on the network, a better mechanism could be through modifications to the tariffs used for this class of
customer.
4.4
Next Steps
•
Determine the standard interface arrangements, connection terms and costs to facilitate connection of
micro- and small-scale embedded generation to the Irish distribution network, taking into consideration
the draft European Norm;
•
Determine the load profile for typical SSEG installations associated with domestic, small commercial and
small industrial customer categories. These profiles can then be adopted within the planning process for
new LV networks;
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•
Determine the levels of SSEG that can be connected to different designs and types of ESB distribution
network without requiring changes to the network
•
Determine the longer-term costs and benefits associated with multiple SSEG connections, based on market
forecasts for different technologies.
•
Determine the best mechanisms for apportioning costs and benefits, given the likely ownership of SSEG
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5.
References
‘The Impact of Small Scale Embedded Generation on the Operating Parameters of Distribution Networks’ by PB
Power for DTI New & Renewable Energy Programme Report number K/EL/00303/04/01
‘Ninth Meeting of the DGCG held on Wednesday 29th October 2003 - Summary of Discussion’
‘DGCG, Technical Steering Group, Work Stream 4 P02A Working Paper 4 Reward Mechanisms for Micro-Generation’
‘Micro-Map Mini and Micro CHP – Market Assessment and Development Plan Summary Report’
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